Potential for a Basin-Centered Gas Accumulation

in Travis Peak (Hosston) Formation,

Gulf Coast Basin, U.S.A.

By Charles E. Bartberger, Thaddeus S. Dyman, and Steven M. Condon

U.S. Geological Survey Bulletin 2184-E

U.S. Department of the Interior

U.S. Geological Survey

Geologic Studies of Basin-Centered Gas Systems

Edited by Vito F. Nuccio and Thaddeus S. Dyman

This work funded by the U.S. Department of Energy, National 

Energy Technology Laboratory, Morgantown, W. Va., under 

contracts DE-AT26-98FT40031 and DE-AT26-98FT40032, and by the 

U.S. Geological Survey Central Region Energy Resources Team
U.S. Department of the Interior

Gale A. Norton, Secretary

U.S. Geological Survey

Charles G. Groat, Director

Any use of trade, product, or fi rm names in this publication

is for descriptive purposes only and does not

imply endorsement by the U.S. Government

This publication is only available online at:

http://geology.cr.usgs.gov/pub/bulletins/b2184-e/

Posted online April 2003, version 1.0
III

Contents

Abstract.......................................................................................................................................................... 1

Introduction ................................................................................................................................................... 1

Data Sources........................................................................................................................................ 2

Acknowledgments............................................................................................................................... 2

Continuous-Type Gas Accumulations ....................................................................................................... 2

Basin-Centered Gas Accumulations ................................................................................................ 3

Method for Evaluating Potential of Basin-Centered Gas in Sandstones 

of the Travis Peak Formation ......................................................................................................... 3

Geologic Setting for Travis Peak Formation in Northern Gulf Coast Basin......................................... 5

Travis Peak Formation Stratigraphy......................................................................................................... 10

Travis Peak Formation Depositional Systems ........................................................................................ 12

Regional Framework ......................................................................................................................... 12

Depositional Environments and Sand-Body Geometry ............................................................... 12

Lower Travis Peak Delta-Fringe Deposits............................................................................. 12

Middle Travis Peak Fluvial Deposits ...................................................................................... 13

Low-Sinuosity Fluvial System ........................................................................................ 13

High-Sinuosity Fluvial System ....................................................................................... 14

Upper Travis Peak Coastal-Plain and Paralic Deposits...................................................... 14

Diagenesis of Sandstones of the Travis Peak Formation..................................................................... 14

Burial History...................................................................................................................................... 14

Sandstone Composition.................................................................................................................... 14

Compaction and Cementation ......................................................................................................... 15

Reservoir Bitumen ............................................................................................................................. 15

Porosity................................................................................................................................................ 15

Permeability........................................................................................................................................ 16

Hydrocarbon Production ........................................................................................................................... 17

Source Rocks .............................................................................................................................................. 18

Burial and Thermal History ....................................................................................................................... 18

Abnormally Pressured Reservoirs ........................................................................................................... 19

Hydrocarbon-Water Contacts .................................................................................................................. 22

Discussion of Evidence For and Against Basin-Centered Gas ........................................................... 24

Source Rocks and Burial and Thermal History............................................................................. 24

Porosity and Permeability ................................................................................................................ 26

Abnormally Pressured Reservoirs .................................................................................................. 28

Hydrocarbon-Water Contacts ......................................................................................................... 30

Conclusions ................................................................................................................................................. 32

References Cited ........................................................................................................................................ 34
IV

Figures

 1A. Map of northeastern Texas showing major fields that have produced 

hydrocarbons from Travis Peak (Hosston) Formation sandstone reservoirs ..................... 4

 1B. Map of northern Louisiana and southern Arkansas showing major fields 

that have produced hydrocarbons from Travis Peak (Hosston) 

Formation reservoirs .................................................................................................................... 5

 1C. Map of central Mississippi showing major fields that have produced 

hydrocarbons from Travis Peak (Hosston) Formation reservoirs......................................... 6

 2. Chronostratigraphic section of northern Louisiana from Shreveport 

Geological Society (1987) showing general stratigraphic succession 

of selected units for northern Gulf Coast Basin ...................................................................... 7

 3. Index map of northern Gulf Coast Basin showing major tectonic features, 

including Sabine arch and Salt Basins of eastern Texas, northern Louisiana, 

and Mississippi ............................................................................................................................. 8

 4. Diagrammatic north-south stratigraphic cross section across southern 

Arkansas and northern Louisiana showing depositional relationships 

among units of Cotton Valley Group and Travis Peak Formation.......................................... 9

 5. East-west stratigraphic cross section of Travis Peak Formation across 

northeastern Texas into western Louisiana showing major Travis Peak 

depositional systems.................................................................................................................. 10

 6. Composite wireline log showing gamma-ray and resistivity responses 

through complete section of Travis Peak Formation in eastern Texas.............................. 11

 7. Semi-log plot of porosimeter porosity versus depth for 1,687 Travis Peak 

Formation sandstone samples from wells in eastern Texas ............................................... 16

 8. Semi-log plot of stressed permeability versus depth for 649 Travis Peak 

Formation sandstone samples from wells in eastern Texas ............................................... 17

 9. Map of northeastern Texas showing fluid-pressure gradients calculated 

from original shut-in pressures in Travis Peak Formation sandstone reservoirs ............ 24

 10. Map of northern Louisiana showing fluid-pressure gradients calculated 

from original shut-in pressures in Travis Peak Formation sandstone reservoirs ............ 25

 11. Map of northeastern Texas showing fields in which hydrocarbon-water 

contacts have been identified in Travis Peak Formation sandstone reservoirs .............. 26

 12. Map of northern Louisiana showing fields in which hydrocarbon-water 

contacts have been identified in Travis Peak Formation sandstone reservoirs .............. 27

 13. Map of northeastern Texas showing measured and average values of 

permeability for productive Travis Peak Formation sandstones in various fields ........... 28

 14. Map of northern Louisiana showing measured values of permeability 

for productive Travis Peak Formation sandstones in various fields .................................. 29

Table

 1. Data for Travis Peak Formation fields in Texas, Louisiana, and Arkansas........................ 20
Abstract

The potential of Lower Cretaceous sandstones of the 

Travis Peak Formation in the northern Gulf Coast Basin to 

harbor a basin-centered gas accumulation was evaluated by 

examining (1) the depositional and diagenetic history and reservoir properties of Travis Peak sandstones, (2) the presence 

and quality of source rocks for generating gas, (3) the burial 

and thermal history of source rocks and time of gas generation 

and migration relative to tectonic development of Travis Peak 

traps, (4) gas and water recoveries from drill-stem and formation tests, (5) the distribution of abnormal pressures based 

on shut-in-pressure data, and (6) the presence or absence of 

gas-water contacts associated with gas accumulations in Travis 

Peak sandstones.

The Travis Peak Formation (and correlative Hosston Formation) is a basinward-thickening wedge of terrigenous clastic 

sedimentary rocks that underlies the northern Gulf Coast Basin 

from eastern Texas across northern Louisiana to southern Mississippi. Clastic infl ux was focused in two main fl uvial-deltaic 

depocenters—one located in northeastern Texas and the other 

in southeastern Mississippi and northeastern Louisiana. Across 

the main hydrocarbon-productive trend in eastern Texas and 

northern Louisiana, the Travis Peak Formation is about 2,000 

ft thick.

Most Travis Peak hydrocarbon production in eastern 

Texas comes from drilling depths between 6,000 and 10,000 

ft. Signifi cant decrease in porosity and permeability occurs 

through that depth interval. Above 8,000-ft drilling depth in 

eastern Texas, Travis Peak sandstone matrix permeabilities 

often are signifi cantly higher than the 0.1-millidarcy (mD) 

cutoff that characterizes tight-gas reservoirs. Below 8,000 ft, 

matrix permeability of Travis Peak sandstones is low because 

of pervasive quartz cementation, but abundant natural fractures 

impart signifi cant fracture permeability. 

Although pressure data within the middle and lower 

Travis Peak Formation are limited in eastern Texas, overpressured reservoirs caused by thermal generation of gas, typical 

of basin-centered gas accumulations, are not common in the 

Travis Peak Formation. Signifi cant overpressure was found in 

only one Travis Peak sandstone reservoir in 1 of 24 oil and gas 

fi elds examined across eastern Texas and northern Louisiana. 

The presence of gas-water contacts is perhaps the most 

defi nitive criterion indicating that a gas accumulation is conventional rather than a “sweet spot” within a basin-centered 

gas accumulation. Hydrocarbon-water contacts within Travis 

Peak sandstone reservoirs were documented in 17 fi elds and 

probably occur in considerably more fi elds across the productive Travis Peak trend in eastern Texas and northern Louisiana. 

All known hydrocarbon-water contacts in Travis Peak reservoirs in eastern Texas, however, occur within sandstones in the 

upper 500 ft of the formation. Although no gas-water contacts 

have been reported within the lower three-fourths of the Travis 

Peak Formation in northeastern Texas, gas production from 

that interval is limited. The best available data suggest that 

most middle and lower Travis Peak sandstones are water bearing in northeastern Texas. 

Insuffi cient hydrocarbon charge relative to permeability 

of Travis Peak reservoirs might be responsible for lack of 

overpressure and basin-centered gas within the Travis Peak 

Formation. Shales interbedded with Travis Peak sandstones in 

eastern Texas are primarily oxidized fl ood-plain deposits with 

insuffi cient organic-carbon content to be signifi cant sources 

of oil and gas. The most likely source rocks for hydrocarbons 

in Travis Peak reservoirs are two stratigraphically lower units, 

the Jurassic-age Bossier Shale of the Cotton Valley Group, 

and laminated, lime mudstones of the Jurassic Smackover 

Formation. Hydrocarbon charge, therefore, might be suffi cient 

for development of conventional gas accumulations, but it is 

insuffi cient for development of basin-centered gas as a result 

of the absence of proximal source rocks and a lack of effective 

migration pathways from stratigraphically or geographically 

distant source rocks.

Introduction

The U.S. Geological Survey (USGS) is reevaluating 

the potential for occurrence of continuous basin-centered 

gas accumulations in selected basins in the United States in 

order to accommodate changing geologic knowledge since 

completion of the USGS 1995 National Petroleum Assessment 

Potential for a Basin-Centered Gas Accumulation 

in Travis Peak (Hosston) Formation, 

Gulf Coast Basin, U.S.A.

By Charles E. Bartberger, Thaddeus S. Dyman, and Steven M. Condon

1
(Gautier and others, 1996). This effort, funded in part by the 

U.S. Department of Energy, might result in identifi cation of 

new continuous-gas plays and petroleum systems or reevaluation of existing plays.

As part of the 1995 National Assessment of United States 

Oil and Gas Resources by the USGS, Schenk and Viger (1996) 

identifi ed three conventional gas plays within the Travis Peak 

and Hosston Formations sandstone trend in eastern Texas and 

northern Louisiana. (The name Hosston Formation is used 

for rocks that are lithologically equivalent to the Travis Peak 

outside Texas.) This report reevaluates the 1995 USGS play 

defi nitions and parameters for establishing those plays through 

more extensive evaluation of data on reservoir properties, 

reservoir pressures, gas and water recoveries, gas-production 

rates, and gas-water contacts in Travis Peak (Hosston) sandstones. Data both favorable and unfavorable for the presence 

of continuous basin-centered gas accumulations are summarized. No attempt is made in this report, however, to identify 

new plays and petroleum systems or to estimate undiscovered 

gas resources for potential plays.

In 1982, under the auspices of its Tight Gas Sands Program, the Gas Research Institute (GRI) conducted a nationwide survey of low-permeability gas-bearing sandstones (Fracasso and others, 1988; Holditch, and others, 1988; Dutton, 

Laubach, Tye, and others, 1991). From that survey, the Lower 

Cretaceous Travis Peak Formation was one of two formations 

selected for comprehensive geologic and engineering research. 

The goals of this research were to develop knowledge to 

improve recovery of gas, and to reduce the costs of producing 

gas, from low-permeability sandstone reservoirs. The main 

emphasis was on developing more effective hydraulic-fracture 

treatments with anticipation of transferring this technology to 

other low-permeability gas reservoirs. As part of this research 

program, the Texas Bureau of Economic Geology (BEG) at 

the University of Texas in Austin conducted comprehensive 

geological analyses of the Travis Peak Formation from 1983 to 

1986. The BEG focus was on depositional systems, sandstone 

diagenesis, natural fractures, source rocks, burial and thermal 

history, and structural evolution of the East Texas and Northern Louisiana Salt Basins and the Sabine uplift. Studies of 

reservoir-engineering properties and production characteristics 

of Travis Peak sandstones in selected gas fi elds also were conducted. Much of this research was based on core, wireline-log, 

and production data that GRI contractors collected from seven 

Travis Peak wells, with permission from operating companies. 

Results from this research prompted GRI to drill and complete 

three Staged Field Experiment (SFE) wells to test understandings developed and to acquire additional data (Dutton, Laubach, Tye, and others, 1991). SFE No. 1 was drilled in August 

1986 in Waskom fi eld, Harrison County, Texas, and SFE No. 2 

was drilled in September 1987 in North Appleby fi eld, Nacogdoches County, Texas. Research in these two wells focused on 

gas-productive sandstones near the top and base of the Travis 

Peak Formation. SFE No. 3 was drilled in September 1988 in 

Waskom fi eld to attempt to apply technologies developed in 

the Travis Peak to low-permeability sandstones of the Cotton 

Valley Group. As a result of research from this GRI Tight Gas 

Sands Program, a wealth of information on Travis Peak and 

Cotton Valley low-permeability sandstone reservoirs was published by both GRI and BEG. Those data and accompanying 

interpretations provide a signifi cant part of the information 

used in this study to evaluate the potential for basin-centered 

gas in the Travis Peak.

Data Sources

Interpretations and conclusions presented in this report 

are based on data from published literature and limited conversations with industry personnel, together with geologic and 

engineering data accessible in a publicly available database 

from IHS Energy Group (PI/Dwights PLUS of Petroleum 

Information/Dwights, d.b.a. IHS Energy Group). PI/Dwights 

PLUS data evaluated for this report are current through February 2000. The primary data from PI/Dwights PLUS pertinent 

to this study are results of drill-stem and production tests 

in the Travis Peak Formation reported for individual wells. 

Because well-completion records depend on information provided by operators, well data in PI/Dwights PLUS might be 

incomplete. 

Acknowledgments

This work is funded by the U.S. Department of Energy, 

National Energy Technology Laboratory, Morgantown, 

W. Va. (contract nos. DE-AT26-98FT40031 and DE-AT26-

98FT40032), and by the U.S. Geological Survey (USGS) 

Central Energy Team. Laura Biewick of the USGS provided 

instruction and assistance in using ArcView software to evaluate Travis Peak and Hosston well and test data. Gregory 

Zerrahn and Joseph Lott, geologists with Palmer Petroleum, 

Shreveport, La., assisted in obtaining reports, maps, and literature. Al Brake, BP Amoco engineer, provided information on 

reservoir pressures, mud-log gas shows, and presumed water 

within the Travis Peak Formation at Woodlawn fi eld in eastern 

Texas. We acknowledge helpful reviews of this manuscript 

by Charles Spencer, Russell Dubiel, and Carol Molnia of the 

USGS.

Continuous-Type Gas Accumulations

It is important to identify continuous-type gas accumulations because resource assessment for such gas accumulations is conducted using different methodology than that used 

for conventional fi elds (Schmoker, 1996). Continuous-gas 

accumulations generally occur within an extensive volume 

of reservoir rock that has spatial dimensions equal to or 

exceeding those of conventional hydrocarbon plays. The defi -

nition of continuous-gas accumulations used here is based 

2 Geologic Studies of Basin-Centered Gas Systems
on geology rather than on government regulations defi ning 

low-permeability (tight) gas. Common geologic and production characteristics of continuous-gas accumulations include 

their occurrence downdip from water-saturated rocks, lack of 

conventional traps or seals, reservoir rocks with low matrix 

permeability, presence of abnormally pressured reservoirs, 

large in-place volumes of gas, and low recovery factors 

(Schmoker, 1996).

Continuous-gas plays were treated as a separate category in the U.S. Geological Survey 1995 National Petroleum 

Assessment and were assessed using a specialized methodology (Schmoker, 1996). These continuous plays are geologically diverse and fall into several categories including coal-bed 

gas, biogenic gas, fractured-shale gas, and basin-centered gas 

accumulations. This report focuses on the potential for basincentered gas within Travis Peak Formation sandstones.

Basin-Centered Gas Accumulations

From studies of hydrocarbon-productive basins in the 

Rocky Mountain region, Law and Dickinson (1985) and Spencer (1987) identifi ed characteristics of basin-centered gas 

accumulations that distinguish them from conventional ones. 

Basin-centered gas accumulations:

 1. Are geographically large, spanning tens to hundreds 

of square miles in areal extent, typically occupying the 

central, deeper parts of sedimentary basins.

 2. Occur in reservoirs having low permeability—generally less than 0.1 millidarcy (mD)—such that gas 

cannot migrate by buoyancy. 

 3. Lack downdip gas-water contacts because gas is not 

held in place by the buoyancy of water. Consequently, 

water production is low or absent. If water is produced, 

it is not associated with a distinct gas-water contact.

 4. Commonly occur in abnormally pressured reservoirs 

(generally overpressured, but in places underpressured).

 5. Contain primarily thermogenic gas, and, where overpressure is encountered, the overpressuring mechanism 

is thermal generation of gas.

 6. Occur structurally downdip from water-bearing reservoirs that are normally pressured or locally underpressured.

 7. Lack traditional seals and trapping mechanisms.

 8. Have gas-prone source rocks proximal to the 

low-permeability reservoirs such that hydrocarbon 

migration distances are short.

 9. Occur in settings such that the tops of the gas accumulations occur within a narrow range of thermal maturity, usually between a vitrinite refl ectance (Ro) of 0.75 

and 0.9 percent.

What causes a basin-centered, continuous-gas accumulation to form? The most common scenario involves 

low-permeability reservoirs in which overpressures develop 

in response to thermal generation of gas. Gas-prone source 

rocks generally must be associated with, or are proximal 

to, low-permeability reservoirs, and this sequence of source 

and reservoir rock must be buried to a depth suffi cient for 

the source rocks to generate gas. Overpressured reservoirs 

develop because the rate of thermal generation of gas exceeds 

the rate at which gas is lost updip by migration through the 

low-permeability reservoir. As overpressure develops, any free 

water in pores of the tight reservoir is forced out updip into 

higher permeability, normally pressured, water-bearing strata. 

Only bound, irreducible water remains in the tight-gas reservoir. Permeability is suffi ciently low within the tight reservoir 

so that gas does not migrate through it by buoyancy as it does 

through conventional reservoirs with higher permeabilities 

(Gies, 1984; Spencer, 1987; Law and Spencer, 1993). Instead, 

gas migrates slowly through the tight-gas reservoir with movement caused by the pressure differential between the region 

of high-pressure gas generation and the normally pressured, 

higher permeability, water-bearing rocks updip where gas does 

migrate upward rapidly by buoyancy. Thus, because of its 

inherent low permeability, a basin-centered gas reservoir itself 

retards the upward migration of gas, in effect forming its own 

leaky seal, and maintaining overpressured conditions.

This scenario probably describes an ideal end-member 

situation. In some cases, for example, basin-centered gas 

accumulations have subnormal reservoir pressures resulting from signifi cant tectonic uplift and erosion of overlying 

strata in the basin. For a basin that is tectonically active and 

in an intermediate stage of uplift, it might be possible to fi nd 

a basin-centered gas accumulation with normally pressured 

reservoirs. It seems clear that particular gas accumulations 

might have only some of the characteristics for basin-centered 

gas described above and that differentiating between basincentered and conventional accumulations often can be diffi cult 

and subjective. It is with this understanding that the potential 

for basin-centered gas in the Travis Peak Formation is evaluated.

Method for Evaluating Potential of 

Basin-Centered Gas in Sandstones 

of the Travis Peak Formation

One of the main requirements for the occurrence of a 

basin-centered, continuous-gas accumulation is the presence 

of a regional seal to trap gas in a large volume of rock across 

a widespread geographic area. In classic basin-centered gas 

accumulations (Law and Dickinson, 1985; Spencer, 1987; 

Law and Spencer, 1993), the regional seal is provided by the 

low-permeability of the reservoir itself, as described above. 

To evaluate the potential for a continuous-gas accumulation 

within the Travis Peak Formation, therefore, it is necessary 

to examine reservoir properties of Travis Peak sandstones 

across the northern Gulf Coast Basin. Because reservoir 

quality of Travis Peak sandstones is governed by diagenetic 

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 3
characteristics, which in turn are controlled primarily by depositional environment, it is helpful fi rst to understand Travis 

Peak depositional systems and related diagenetic patterns.

Although gas production from Travis Peak sandstones 

seems to occur from discrete fi elds, it is necessary to determine if those fi elds are separate, conventional accumulations 

or so-called “sweet spots” within a regional, continuous-gas 

accumulation. Thus, it is essential to understand what characterizes the apparent productive limits of existing Travis Peak 

gas fi elds, including the presence or absence of gas-water 

contacts. Additionally, because continuous-gas accumulations 

commonly are characterized by overpressure associated with 

thermal generation of gas from source rocks that generally 

are proximal to low-permeability reservoirs, it is important to 

evaluate the presence and quality of potential source rocks, 

burial and thermal history of those source rocks, and reservoirpressure data.

In northeastern Texas, the 2,000-ft-thick Travis Peak 

Formation is characterized by heterogeneities that require 

caution when evaluating the potential for basin-centered gas 

accumulations. Because permeability decreases by four orders 

of magnitude across the productive depth range from (6,000 to 

10,000 ft), it is inappropriate to characterize the entire Travis 

Peak Formation in a particular well using a single permeability 

value. Because of depositional heterogeneities, sandstones 

in the upper 300 ft of the Travis Peak commonly are isolated 

bodies encased in shales, whereas the bulk of the underlying 

Travis Peak consists of interconnected, multistory, multilateral 

sandstone bodies that lack regional shale barriers. Whereas a 

single fl uid-pressure gradient might characterize much of the 

interconnected sandstone sequence, that gradient might be 

considerably different than the gradient for one of the isolated 

sandstone units in the upper Travis Peak, hence the diffi culty 

in attempting to characterize the entire formation with one 

fl uid-pressure gradient. Likewise, the presence of a gas-water 

contact within one upper Travis Peak sandstone reservoir 

in a particular Travis Peak fi eld might not be characteristic 

of deeper Travis Peak reservoirs in the same area. Finally, 

because most Travis Peak hydrocarbon production in northeastern Texas is from sandstone reservoirs within the upper 

Angelina

Houston

Rockwall

0 20 40 Miles 10 30

Travis Peak gas

Travis Peak oil

TEXAS

LOUISIANA

AR

LA

Collin Hunt

Ellis

Navarro

Hill

Falls

Limestone Freestone

Leon

Anderson

Cherokee

Nacogdoches

Rusk

Smith

Henderson

Van Zandt

Gregg

Upshaw

Wood

Camp

Rains

Hopkins Franklin

Titus

Morris Cass

Marion

Harrison

Miller

Caddo

De Soto

Shelby

Panola

Sabine

San Augustine

Hemphill

CHAPEL HILL

TRI CITIES

OPELIKA

BLACKFOOT

PERCY WHEELER

RISCHERS STORE

REED

TEAGUE WEST

McBEE

POKEY

WHITE OAK

CREEK TRAWICK

APPLEBY

NORTH

CARTHAGE

PINEHILL SOUTHEAST

DANVILLE

HENDERSON

HENDERSON

SOUTH

CYRIL

MINDEN

JOAQUIN

BETHANYLONGSTREET

WASKOM

LONGWOOD

WILLOW

SPRINGS

LANSING

NORTH

WHELAN

CEDAR SPRINGS

LASSATER

Dallas

Kaufman Gulf of Mexico

TX

LA

OK AR

DETAIL MS AL

AREA

LOCATION MAP WOODLAWN

1A

Figure 1A. Map of northeastern Texas showing major fi elds that have produced hydrocarbons from Travis Peak (Hosston) Formation sandstone 

reservoirs.

4 Geologic Studies of Basin-Centered Gas Systems
300 ft of the formation, signifi cantly fewer data are available 

to characterize the lower three-fourths of the Travis Peak.

Geologic Setting for 

Travis Peak Formation 

in Northern Gulf Coast Basin

The Lower Cretaceous Travis Peak Formation is a 

basinward-thickening wedge of terrigenous clastic sedimentary rock that underlies the northern Gulf of Mexico coastal 

plain from eastern Texas across southern Arkansas and northern Louisiana into southern Mississippi, southern Alabama, 

and the Florida Panhandle. The thickness of the Travis Peak 

Formation ranges from less than 1,000 ft in southern Arkansas 

to more than 3,200 ft in north-central Louisiana. The downdip 

limit of the Travis Peak Formation has not been delineated 

by drilling to date. Travis Peak strata crop out in portions of 

Brown, Mills, McCulloch, San Saba, and Lampasas Counties 

in east-central Texas (Hartman and Scranton, 1992). Across 

the hydrocarbon-productive trend of the Travis Peak Formation (fi gs. 1A, 1B, and 1C), the depth to top of the Travis Peak 

ranges from about 4,000 ft below sea level in southern Arkansas to more than 18,000 ft below sea level in north-central 

Louisiana and southern Mississippi (Saucier, 1985). Although 

Travis Peak sandstones produce gas from drilling depths in 

excess of 16,000 ft in southern Mississippi (Thomson, 1978), 

most Travis Peak production across the trend in eastern Texas 

and northern Louisiana is from drilling depths between 6,000 

and 10,000 ft (Dutton and others, 1993). Travis Peak production across eastern Texas and northern Louisiana is primarily 

gas, but some fi elds also produce oil (fi gs. 1A and 1B). 

The Travis Peak (Hosston) is the basal formation of the 

Lower Cretaceous Trinity Group, which overlies the Upper 

Jurassic and Lower Cretaceous Cotton Valley Group (fi g. 2). 

The Cotton Valley Group and overlying Travis Peak Formation 

represent the fi rst two major infl uxes of terrigenous clastic sediments into the Gulf Coast Basin following its initial formation 

during continental rifting in Late Triassic time (Salvador, 1987; 

Worrall and Snelson, 1989). The earliest sedimentary deposits 

in East Texas and Northern Louisiana Salt Basins (fi gs. 2 and 3) 

TEXAS

LOUISIANA

ARKANSAS

LOUISIANA

MISSISSIPPI

Cass

Miller

Lafayette Columbia

Webster

Caddo

Marion

Harrison

Claiborne

Panola

Shelby

De Soto

Sabine

Natchitoches

Red River

Beinville

Lincoln

Jackson

Union

Union

Ashley

Morehouse

Chicot

West

Carroll

East

Carroll

Ouachita

Richland

Madison

Franklin

Tensas

Catahoula LaSalle

Grant

Concordia

Winn LOUISIANA

Caldwell

0 20 40 Miles 10 30

Travis Peak gas

Travis Peak oil

LISBON

ATHENS

SUGAR

CREEK

LISBON NORTH

ARCADIA

HICO-KNOWLES

DOWNSVILLE

RUSTON

CHOUDRANT

SIMSBORO

CLAY CALHOUN

CHATHAM

CLEAR BRANCH

CHENIERE

CREEK

VIXEN

COTTON PLANT

Dallas

Kaufman Gulf of Mexico

TX

LA

OK AR

DETAIL MS AL

AREA

LOCATION MAP Bossier

WASCOM

BETHANYLONGSTREET

CASPIANA

SHREVEPORT

ELM

GROVE

COTTON

VALLEY

LEATHERMAN

CREEK

SIBLEY

LUCKY

SAILES

BRYCELAND

WEST

DANVILLE

ADA

HODGE

BEAR CREEK

BRYCELAND

VILLAGE

1B

Figure 1B. Map of northern Louisiana and southern Arkansas showing major fi elds that have produced hydrocarbons from Travis Peak 

(Hosston) Formation reservoirs. Modifi ed from Bebout and others (1992).

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 5
include Upper Triassic and Lower Jurassic nonmarine red beds 

of the Eagle Mills Formation, the thick Middle Jurassic evaporite sequence known as the Werner Anhydrite and the Louann 

Salt, and the nonmarine Norphlet Formation. Following a major 

regional marine transgression across the Norphlet, regressive 

carbonates of the Upper Jurassic Smackover Formation were 

deposited and capped by red beds and evaporites of the Buckner 

Formation (fi g. 2). A subsequent minor marine transgression is 

recorded by the Gilmer Limestone (“Cotton Valley limestone”) 

in eastern Texas, although equivalent facies in northern Louisiana and Mississippi are terrigenous clastics known as the 

Haynesville Formation. The marine Bossier Shale, lowermost 

formation of the Cotton Valley Group (fi g. 2), was deposited 

conformably atop the Gilmer-Haynesville, followed by progradation of the major fl uvial-deltaic sequence known as the 

“Cotton Valley sandstone” or Schuler Formation (fi g. 2). 

0 20 40 Miles 10 30

Travis Peak oil/gas fields

MISSISSIPPI

LOUISIANA

Kaufman Gulf of Mexico

TX

LA

OK AR

AL

MS

DETAIL

AREA

LOCATION MAP

Hinds

Copiah

Rankin

Simpson

Lincoln

Lawrence

Jefferson Davis Covington Jones

Forrest

Lamar

Marion

Stone

Pearl River

Hancock Harrison

St Tammany

Washington St Helena

Tangipahoa

Amite Pike Walthall

McRANEY

WHITESAND

BASSFIELD

OAKVILLE HOLIDAY CREEK

GREENS CREEK

MONTICELLO

MORGANTOWN EAST

KNOXO

SANDY HOOK WEST

POPLARVILLE

TATUMS CAMP

1C

Figure 1C. Map of central Mississippi showing major fi elds that have produced hydrocarbons from 

Travis Peak (Hosston) Formation reservoirs. Modifi ed from Bebout and others (1992).

6 Geologic Studies of Basin-Centered Gas Systems
CHRONOSTRATIGRAPHIC SECTION OF NORTH LOUISIANA

SYSTEM

SERIES

STAGE GROUP/FORMATION

TERTIARY

PALEOGENE

PALEOCENE

EOCENE

AGE

(MA)

GULFIAN

CRETACEOUS

COMANCHEAN COAHUILAN

JURASSIC

UPPER MIDDLE LOWER UPPER

TRIASSIC

YPRESIAN

THANETIAN

DANIAN

MAASTRICHTIAN

CAMPANIAN

SANTONIAN

CONIACIAN

TURONIAN

CENOMANIAN

ALBIAN

APTIAN

BARREMIAN

HAUTERIVIAN

VALANGINIAN

BERRIASIAN

TITHONIAN

KIMMERIDGIAN

OXFORDIAN

CALLOVIAN

BATHONIAN

BAJOCIAN

AALENIAN

TOARCIAN

PLIENSBACHIAN

SINEMURIAN

HETTANGIAN

RHAETIAN

WILCOX

MIDWAY

ARKADELPHIA

NACATOCH

EAGLE FORD

SARATOGA

ANNONA

OZAN

TOKIO

AUSTIN

TUSCALOOSA

PALUXY WASHITA-FREDERICKSBURG

MOORINGSPORT

FERRY LAKE ANHYDRITE

RODESSAJAMES PINE ISLAND

PETTET

SLIGO

HOSSTON

(TRAVIS PEAK)

SCHULER

BOSSIER

HAYNESVILLE-BUCKNER

SMACKOVER

NORPHLET

LOUANN

WERNER

EAGLE MILLS

60

70

80

90

100

110

120

130

140

150

160

170

180

190

200

210

MILLIONS OF YEARS

TRINITY GROUP

GLEN ROSE

UPPER CRETACEOUS LOWER CRETACEOUS

COTTON

VALLEY

GROUP

Figure 2. Chronostratigraphic section of northern Louisiana from Shreveport Geological Society (1987) 

showing general stratigraphic succession of selected units for northern Gulf Coast Basin. Travis Peak 

Formation, lowermost formation of the Trinity Group, is designated as Hosston Formation (shading) on 

this diagram. Upper contact of Travis Peak (Hosston) with overlying Sligo Formation carbonates is time 

transgressive.

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 7
A signifi cant marine transgression that halted Cotton 

Valley fl uvial-deltaic sedimentation is recorded by the 

Knowles Limestone, the uppermost formation of the Cotton 

Valley Group (fi g. 4). Prodelta and fl uvial-deltaic deposits of 

the Travis Peak Formation overlie the Knowles Limestone, 

recording the second major infl ux of terrigenous clastics into 

the northern Gulf Coast Basin. In updip regions of the Gulf 

Coast Basin, the Knowles Limestone pinches out, and Travis 

Peak fl uvial-deltaic strata rest directly on Schuler fl uvial deltaic units of the Cotton Valley Group (fi g. 4). Whereas most 

workers consider the Knowles–Travis Peak contact to be conformable, controversy exists regarding the presence or absence 

of an unconformity between the updip Schuler and Travis Peak 

Formations. McFarlan (1977), Todd and Mitchum (1977), 

and Tye (1989) identify a major unconformity between the 

Schuler and Travis Peak, whereas Nichols and others (1968) 

and Saucier (1985) consider the contact to be conformable. 

There is general agreement that the upper contact of the Travis 

Peak with overlying shallow-marine carbonates of the Sligo 

Formation (known as the Pettet Formation outside Texas) is 

conformable. Most of the 15-m.y. period of Travis Peak deposition occurred during a relative rise in sea level (McFarlan, 

1977; Vail and others, 1977), and the Travis Peak–Sligo contact is a time-transgressive boundary with Sligo oolitic and 

micritic limestones onlapping Travis Peak paralic and marine 

clastics to the north out of the Gulf Coast Basin (Tye, 1991) 

(fi gs. 2 and 4).

The thick Middle Jurassic Louann Salt became mobile as 

a result of sediment loading and associated basinward tilting in 

Late Jurassic and Early Cretaceous time. Salt movement was 

initiated during Smackover carbonate deposition and became 

more extensive with infl ux of the thick sequence of Cotton 

Valley and Travis Peak clastics (McGowen and Harris, 1984). 

Many Cotton Valley and Travis Peak fi elds in eastern Texas, 

34°N

32°N

30°N

96°W 94°W 92°W 90°W

LOUISIANA

ARKANSAS

LOUISIANA

TEXAS

LOUISIANA

MISSISSIPPI

MISSISSIPPI

SALT

BASIN

NORTH

LOUISIANA

SALT

BASIN

MONROE

UPLIFT

SABINE

ARCH

COMANCHEAN SHELF EDGE

EAST

TEXAS

SALT

BASIN

MEXIA-TALCO FAULT ZONE

FAULT ZONE

GINGER

FAULT ZONE MT ENTERPRISE

FAULT

ARKANSAS

ZONE

SOUTH

FAULT

ZONE

PICKENS

ANCESTRAL

MISSISSIPPI RIVER

TRAVIS PEAK

DEPOCENTER

(SAUCIER, 1985)

ANCESTRAL

RED RIVER

TRAVIS PEAK

DEPOCENTER

(SAUCIER, 1985)

APPROX DOWNDIP LIMIT

OF TRAVIS PEAK SANDSTONE

FROM SANDSTONE ISOPACH

MAPS OF SAUCIER (1985)

0 20 40 60 80

MILES

GULF OF MEXICO

Figure 3. Index map of northern Gulf Coast Basin from Dutton and others (1993) showing major tectonic features, including Sabine arch and 

salt basins of eastern Texas, northern Louisiana, and Mississippi. Sabine and Monroe uplifts were not positive features during deposition of 

the Lower Cretaceous Travis Peak Formation. Movement of salt in the salt basins commenced during deposition of Upper Jurassic Smackover 

Formation carbonates and became more extensive with infl ux of thick sequence of Cotton Valley Group and Travis Peak Formation terrigenous 

clastic sediments.

8 Geologic Studies of Basin-Centered Gas Systems
Sligo Formation

Travis Peak

(Hosston)

Formation

TRINITY GROUP

ARKANSAS

LOUISIANA

NORTH 

COTTON

VALLEY

GROUP

(fluvial-deltaic sandstones)

Schuler Fm

(fluvial-deltaic

sandstones)

Hico Shale

(lagoonal)

Knowles Limestone

Terryville Sandstone (massive ss complex)

Winn Limestone

Troy Ls

?

contact projected

Calvin Ss

Restricted marine shale

Bossier Formation

(marine shale)

CRETACEOUS

JURASSIC

1000

500

0

Feet

0 10 20

Miles

S

N

AR

LA

INDEX

MAP

Sligo

Formation

Travis Peak

(Hosston)

Formation

TRINITY GROUP

ARKANSAS

LOUISIANA

NORTH 

COTTON

VALLEY

GROUP

(fluvial-deltaic sandstones)

Schuler Fm

(fluvial-deltaic

sandstones)

Hico Shale

(lagoonal)

Knowles Limestone

Terryville Sandstone (massive-ss

complex)

Winn Limestone

Troy

Ls

?

contact projected

Calvin Ss

Restricted-marine shale

Bossier Formation

(marine shale)

CRETACEOUS

JURASSIC

1000

500

0

Feet

0 10 20

Miles S

N

AR

LA

INDEX

MAP

Figure 4. Diagrammatic north-south stratigraphic cross section across southern Arkansas and northern Louisiana showing depositional relationships among 

Group and Travis Peak Formation (from Saucier, 1985). Datum is top of Cotton Valley Group. Relatively thick sequence of Cotton Valley (Terryville) Sandstone, inKnowles Limestone separates Bossier Shale source rocks from Travis Peak sandstone reservoirs. Coleman and Coleman (1981) consider Calvin Sandstone anpart of Cotton Valley Group. 
Louisiana, and Mississippi are structural or combination traps 

associated with deformed Louann Salt. Salt structures range 

from small, low-relief salt pillows to large, piercement domes 

(McGowen and Harris, 1984; Kosters and others, 1989).

The Sabine uplift (fi g. 3) is a broad, low-relief, basementcored arch separating the East Texas and Northern Louisiana 

Salt Basins. With vertical relief of 2,000 ft, the Sabine uplift 

has a closed area exceeding 2,500 mi2 (Kosters and others, 

1989). Isopach data across the uplift indicate that it was a positive feature during deposition of Louann Salt in the Jurassic 

but that main uplift occurred in late, mid-Cretaceous (101 to 

98 Ma) and early Tertiary time (58 to 46 Ma) (Laubach and 

Jackson, 1990; Jackson and Laubach, 1991). As a high area 

during the past 60 m.y., the Sabine uplift has been a focal area 

for hydrocarbon migration in the northern Gulf Coast Basin 

during that time. Numerous smaller structural highs on the 

Sabine uplift in the form of domes, anticlines, and structural 

noses provide traps for hydrocarbon accumulations, including 

many oil and gas fi elds with Travis Peak reservoirs. Interpretations of the origins of these smaller structures have included 

salt deformation and small igneous intrusions, as summarized 

by Kosters and others (1989). Because the Louann Salt is thin 

across the Sabine uplift, Kosters and others (1989) suggested 

that most of the smaller structures across the Sabine uplift 

developed in association with igneous activity.

Travis Peak Formation Stratigraphy

The Travis Peak Formation is not divided formally into 

members. However, Saucier (1985) and Saucier and others 

(1985) distinguished three separate stratigraphic intervals 

within the Travis Peak across eastern Texas and northern 

Louisiana based on relative amounts of sandstone and shale, 

as refl ected in the resistivity and gamma-ray character of 

sandstones on wireline logs. A thin, basal interval of mixed 

sandstones and shales interpreted as delta-fringe gradationally 

0

1000

2000

3000

4000

Depth, in Feet

126 Miles

TEXAS LOUISIANA

A

WEST

A'

EAST

Datum

Travis Peak Formation

Shelf

Paralic

Deltaic

Fluvial

Shelf

A A'

TEXAS

LOUSIANA

LOCATION MAP

Figure 5. East-west stratigraphic cross section of Travis Peak Formation across northeastern Texas into western Louisiana showing major 

Travis Peak depositional systems (from Dutton, Laubach, and Tye, 1991). Cross section oriented parallel to depositional dip. Three-fold division 

of Travis Peak Formation across hydrocarbon-productive trend includes thin, basal deltaic unit overlain by thick fl uvial sequence that grades 

upward into paralic deposits. Vertical lines represent locations of oil and gas wells. Datum is top of Pine Island Shale.

10 Geologic Studies of Basin-Centered Gas Systems
TRAVIS PEAK FORMATION

GAMMA

RAY RESISTIVITY 100 FT

Coastal Plain / Paralic / Marine

(Isolated distributary-channel,

tidal-channel, and tidal-flat

sandstones encased in shales)

High-Sinuosity Fluvial

(Isolated channel sandstones encased in

laterally extensive flood-plain shales)

Low-Sinuosity Fluvial

(Stacked channel and splay sandstones

with minor flood-plain shales)

Delta Fringe / Marginal Marine

(Alternating shales and sandstones deposited

during initial progradation of Travis Peak)

COTTON VALLEY GROUP

COMPOSITE LOG PROFILE OF TRAVIS PEAK FORMATION

Figure 6. Composite wireline log showing gamma-ray and resistivity responses through complete section of Travis Peak Formation in eastern 

Texas (modifi ed from Davies and others, 1991). Gamma-ray and resistivity character distinguish thin basal deltaic sequence, thick middle 

fl uvial sequence, and thin upper paralic interval. Log responses within thick fl uvial sequence also distinguish lower interval of stacked braidedchannel sandstones with minor fl ood-plain mudstones from upper interval of meandering-channel sandstones encased in thicker overbank 

mudstones. Most Travis Peak hydrocarbon production in northeastern Texas comes from sandstones encased in shales within the upper 300 ft 

of the Travis Peak Formation. Depth increments on log are 100 ft.

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 11
is overlain by a thick, sandstone-rich sequence of fl uvial and 

fl ood-plain deposits that grades upward into another interval 

of sandstone and mudstone interpreted as coastal-plain and 

paralic deposits (fi gs. 5 and 6) (Saucier, 1985; Fracasso and 

others, 1988; Tye, 1989, 1991). The middle fl uvial–fl oodplain interval, which is thickest and forms the bulk of the 

Travis Peak section, consists of stacked, aggradational, 

braided-channel sandstones that grade upward into more isolated meandering-channel sandstone deposits (fi g. 6). Sandstones are interpreted as braided, based on blocky SP curves, 

bed forms observed in conventional cores, and sandstone-body 

geometry. Stacked, braided-channel units generally are 12 to 

45 ft thick, but, because of the absence of preserved shales, 

amalgamated channel sandstones occur in places as massive 

sandstone units as much as 250 ft thick with blocky SP curves 

(Saucier, 1985). Serrated gamma-ray curves within such intervals refl ect abundant shale rip-up clasts at the scoured bases of 

individual channels (Tye, 1989). Upward-fi ning sequences are 

not common and occur only where individual channel units 

are isolated by siltstones and (or) shales (Saucier, 1985).

This thick fl uvial–fl ood-plain sequence gradationally 

overlies a much thinner sequence with considerably higher 

mudstone content in which discrete sandstones are separated 

by thicker mudstones. Sandstones in this lower Travis 

Peak sequence display a variety of upward-coarsening, 

upward-fi ning, and serrated SP signatures and are interpreted 

as delta-fringe deposits. 

The thick, middle fl uvial–fl ood-plain sequence grades 

upward into the third interval recognized by Saucier (1985), 

which forms the uppermost portion of the Travis Peak. Like 

the lower Travis Peak delta-fringe interval, this upper interval 

is characterized by discrete sandstones separated by thicker 

mudstones (fi g. 6). Many sandstones in the upper interval 

display thin, spiky, upward-coarsening or upward-fi ning serrated SP signatures, which are interpreted as coastal-plain 

and paralic deposits. Upper Travis Peak paralic units are 

transgressive and step upward and landward with time (fi g. 

2) as they interfi nger with, and are gradationally overlain by, 

shallow-marine shelf carbonates of the Sligo (Pettet) Formation (Fracasso and others, 1988). Sligo carbonates thin updip 

to the northwest as they lap onto Travis Peak paralic deposits. 

Contact of the Travis Peak with the overlying Sligo Formation, 

therefore, is time transgressive.

Travis Peak Formation 

Depositional Systems

Regional Framework

Following the regional marine transgression recorded by 

deposition of the Knowles Limestone at the close of Cotton 

Valley time, Travis Peak fl uvial-deltaic systems began prograding basinward across surfaces of the Schuler and Knowles 

Formations (fi g. 4). Two main Travis Peak fl uvial-deltaic 

depocenters (fi g. 3) have been documented along the arcuate 

northern Gulf Coast Basin (Saucier, 1985; Tye, 1989). One 

depocenter was located in northeastern Texas where the ancestral Red River fl owed into the area of the East Texas Salt Basin 

through a structural downwarp in the Ouachita thrust belt. The 

drainage area of the ancestral Red River most likely spanned 

a large part of the present-day Southwestern and Midwestern 

United States. Coarse clastic sediment probably was derived 

from highlands in western Utah and southern Arizona. Triassic 

red beds were exposed in the provenance area during Travis 

Peak time, and these might be the source of abundant red 

siltstones within the Travis Peak Formation in eastern Texas 

(Saucier, 1985). 

The second Travis Peak depocenter was situated in 

southern Mississippi and northeastern Louisiana where the 

ancestral Mississippi River, which had developed as a major 

fl uvial system during Cotton Valley time (Coleman and 

Coleman, 1981), continued to transport clastic sediments to 

elongate Travis Peak deltas in the northeastern Gulf Coast 

Basin (Reese, 1978; Saucier, 1985; Tye, 1989). Evidence 

for the presence of these two depocenters is provided by 

sandstone isopach patterns from Saucier (1985), who divided 

the Travis Peak section at its midpoint and mapped gross 

sandstone thickness of the lower and upper halves of the 

formation. 

Across the Travis Peak hydrocarbon-productive trend in 

eastern Texas, the formation has been divided informally into 

three sequences based on relative amounts of sandstone and 

shale, as described above. However, because of rapid early 

progradation of Travis Peak fl uvial-deltaic systems, the lowermost delta-fringe sequence is thin (fi gs. 5 and 6). With the bulk 

of the Travis Peak Formation deposited during a relative rise 

in sea level, the formation can be considered to be comprised 

of two main units: a lower aggradational to retrogradational 

fl uvial sequence, and an upper retrogradational coastal-plain/

paralic sequence

Depositional Environments and 

Sand-Body Geometry

Lower Travis Peak Delta-Fringe Deposits

The basal 100 to 500 ft of the Travis Peak Formation 

across much of eastern Texas is characterized by discrete 

sandstones separated by thicker mudstones. Sandstones display upward-coarsening to upward-fi ning, spiky to serrated 

SP signatures, and are interpreted as representing distributarychannel, distributary-mouth-bar, delta-front, interdistributarybar, and barrier-bar environments (Saucier, 1985). Upward in 

this section, sandstones become thicker and the log character 

changes from upward-coarsening to blocky, as depositional 

systems grade into the thick, massive, sandstone-rich fl uvial 

section of the middle Travis Peak. Across much of eastern 

12 Geologic Studies of Basin-Centered Gas Systems
Texas, lower Travis Peak delta-fringe deposits are absent, and 

Travis Peak fl uvial sandstones directly overlie the Knowles 

Limestone or its updip fi ne-grained clastic equivalents (Saucier, 1985). This is because the stable Travis Peak shelf, which 

is underlain by continental crust, probably did not subside 

readily relative to the rate of lower Travis Peak deposition, 

and early Travis Peak rivers eroded and reworked their own 

delta-fringe deposits as Travis Peak fl uvial-deltaic systems 

prograded seaward (Saucier, 1985). Little analysis is devoted 

to these lower delta-fringe sandstones in the Travis Peak literature, nor is any mention made of hydrocarbon production 

from them. Perhaps this is because they are absent across 

much of the updip portion of the East Texas Basin, and also, 

as discussed below in the section on diagenesis, reservoir 

properties of Travis Peak sandstones deteriorate signifi cantly 

with depth.

Middle Travis Peak Fluvial Deposits

The middle Travis Peak sandstone-rich fl uvial interval 

accounts for approximately three-fourths of the 2,000-ft thickness of the formation in eastern Texas (fi gs. 5 and 6). Travis 

Peak fl uvial systems prograded rapidly seaward across the 

East Texas Basin, then slowly retreated landward, primarily in 

response to the relative rise in sea level that occurred during 

Early Cretaceous time (McFarlan, 1977; Todd and Mitchum, 

1977; Tye, 1989, 1991). However, the thick sequence of Travis 

Peak fl uvial sandstones and associated fi ner grained fl oodplain deposits refl ects deposition during a time when sediment supply and development of accommodation space (shelf 

subsidence) were in approximate balance. Although channel 

sandstones generally are stacked, amalgamated units with 

scoured basal contacts, there is little evidence of signifi cant 

incision within the thick Travis Peak fl uvial sequence (Davies 

and others, 1991). 

The relative rise in sea level that occurred during Travis 

Peak time might have been responsible for an observed evolution in patterns of fl uvial deposition from braided to meandering (fi g. 6) (Tye, 1989, 1991). Regional stratigraphic studies 

across East Texas Basin suggest that early Travis Peak fl uvial 

systems consisted of low-sinuosity, braided channels with bedload movement of sand as the dominant sediment-transport 

mechanism. With relative rise in sea level, late Travis Peak 

fl uvial systems evolved into higher sinuosity braided and 

meandering rivers that carried signifi cantly larger volumes of 

mud in suspension, in addition to sand bed load. Data from 

cores indicate that channel sandstones comprise 65 percent of 

the total rock volume in the low-sinuosity fl uvial section, with 

the remaining 35 percent being fi ner grained, argillaceous, 

crevasse-splay sandstones and overbank mudstones (Davies 

and others, 1991). In the higher sinuosity, meandering fl uvial 

system, channel sandstones comprise only 30 percent of the 

section, with 70 percent of the rock volume consisting of fi negrained, argillaceous, overbank sandstones and fl ood-plain 

shales. 

Whereas Tye (1989, 1991) suggests that Travis Peak 

fl uvial systems evolved from low to high sinuosity with time, 

Davies and others (1991) report that channel type varies more 

with geographic position within the Travis Peak depocenter. 

They suggest that high-sinuosity channels comprise the bulk 

of the fl uvial section on the northeastern fl ank of the Travis 

Peak depocenter, whereas low-sinuosity channels predominate in central portions of the depocenter. Davies and others 

(1991), however, admit that distinguishing between high- and 

low-sinuosity channel systems using wireline logs alone is diffi cult in the absence of core data, and they recognize that most 

of the 2,000-ft Travis Peak section in East Texas Basin is not 

cored. Evolution of fl uvial systems from low to high sinuosity with time is consistent with the documented relative rise 

in sea level, gradation of fl uvial deposits into paralic deposits 

in the upper Travis Peak, and culmination of the transgression with deposition of Sligo carbonates. Marzo and others 

(1988) showed that, in moving from proximal to distal positions within a fl uvial-sheet sandstone sequence, amalgamated 

sandstone bodies become less connected and more separated 

by mudstones. Vertical change from stacked braided-channel 

sandstones to meandering-channel sandstones isolated within 

fl ood-plain shales in the Travis Peak Formation would therefore be expected at any given location in the East Texas Basin 

as a result of landward displacement of fl uvial-deltaic facies 

during the overall Travis Peak transgression. 

Low-Sinuosity Fluvial System

Within the Travis Peak low-sinuosity fl uvial system, 

average thickness of individual channel sandstones is 8 ft 

(Davies and others, 1991). Abandoned-channel deposits of 

gray-black shale that cap channel sandstones are not common 

and, where present, are only a few inches thick. Because 

channel sandstones refl ect successive fl ood events and tend 

to accumulate in vertical or en-echelon patterns, solitary 

channel deposits are rare. Although channels have scoured 

basal contacts, signifi cant amounts of incision have not been 

observed. Basal-lag conglomerates with black-shale clasts are 

thin and generally occur only above underlying channels that 

are capped by thin abandonment units. Travis Peak amalgamated channel-sandstone units range from 12 to 45 ft thick and 

consist of two to fi ve stacked channels (Davies and others, 

1991). In places, massive sandstone units are as much as 250 ft 

thick (Saucier, 1985). Sedimentary structures consist predominantly of planar cross-stratifi cation and horizontal laminations, 

with minor amounts of ripples (Tye, 1991; Davies and others, 

1991). Because of the low amount of mud transported as suspended load, mud drapes are not common. Main barriers to 

fl ow that might compartmentalize these reservoir sandstones, 

therefore, are zones where porosity is occluded as a result 

of extensive quartz cementation. Stacked channel-sandstone 

sequences are capped by red and gray fl ood-plain mudstones 

and siltstones that commonly show evidence of roots and 

would seem to provide top seals. However, lateral switching in 

conjunction with vertical and en-echelon stacking of channels 

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 13
results in multilateral and multistory sandstone units that span 

wide geographic areas and probably have complex interconnections with respect to pressure communication and fl uid 

migration. 

Low-sinuosity channels are broad, tabular sandstone 

bodies, with thickness-to-width ratios of approximately 1:

800 (Tye, 1991; Dutton, Laubach, Tye, and others, 1991). 

At North Appleby fi eld in Nacogdoches County, Texas, Tye 

(1991) found channel-belt widths ranging from 3 to 6 miles. In 

a gas-productive zone at the base of the low-sinuosity fl uvial 

section at North Appleby fi eld, Tye (1991) reported average 

thickness of stacked channel-belt sandstones to be 26 ft and 

average channel-belt width to be 4.5 miles. Patterns of channel 

avulsion in low-sinuosity rivers tend to result in preservation of 

long sandstone bodies; Davies and others (1991) demonstrated 

that Travis Peak channel-belt sandstone bodies commonly span 

areas of 5,000 acres or more. Tye (1991) reports individual productive channel-belt sandstone bodies can cover 25,000 acres.

High-Sinuosity Fluvial System

High-sinuosity channel deposits in the Travis Peak Formation commonly include both a lower sandstone unit that 

accumulated as a migrating point-bar deposit in an active 

channel and an overlying mudstone plug deposited in the 

abandoned-channel stage (Davies and others, 1991). Pointbar sandstone thickness in the Travis Peak commonly is 12 to 

15 ft, with the lower 8 to 10 ft consisting of relatively clean, 

trough-crossbedded sandstone overlain by a thinner sequence 

of fi ner grained, often shaly, rippled sandstone with mudstone 

drapes. Mudstone drapes are deposited during periods of 

normal, low-velocity fl ow between fl ood events, and collectively they can compartmentalize the upper parts of point-bar 

sandstone units. Eventual cut-off of meanders by channel avulsion during fl oods resulted in isolation of point-bar sandstone 

units. Although high-sinuosity channel sandstone units in the 

Travis Peak locally exhibit vertical stacking or cross-cutting of 

successive units, most such point-bar sandstones are isolated 

from each other by overbank mudstones and siltstones, which 

comprise 70 percent of the high-sinuosity sequence (Davies 

and others, 1991). High-sinuosity Travis Peak fl uvial-channel 

deposits generally have thickness-to-width ratios of 1:100 

(Dutton, Laubach, Tye, and others, 1991, Dutton, Laubach, 

and Tye, 1991). Estimates of the size of fully developed Travis 

Peak point-bar units are approximately 300 acres, a fi gure 

that agrees closely with drainage areas predicted from GRI 

reservoir-engineering simulations (Davies and others, 1991).

Upper Travis Peak Coastal-Plain 

and Paralic Deposits

Cores from the upper Travis Peak interval reveal a diverse 

assemblage of environments within the Travis Peak Formation, and this diversity manifests itself along depositional 

dip from northwest to southeast across eastern Texas into 

northern Louisiana (Tye, 1989). In updip regions, sandstones 

represent meandering-channel and overbank, crevasse-splay 

deposits, and they grade downdip into distributary-channel, 

distributary-mouth-bar, delta-front, and interdistributary-bar 

deposits. Farther downdip, sandstones were deposited in estuarine, tidal-fl at, tidal-channel, and marine settings. Point-bar 

sandstones in updip coastal-plain settings are slightly thinner 

(5 to 15 ft thick) than those in the underlying high-sinuosity 

channel sequence but exhibit similar characteristics, including 

isolation from each other within overbank mudstone deposits (Tye, 1989). Farther downdip, blocky to upward-fi ning 

sandstones 10 to 25 ft thick display trough and ripple crossbedding with abundant burrows, fl aser bedding, bidirectional 

cross-stratifi cation (indicative of tidal currents), coal streaks 

and organic debris, and, in places, bivalve and gastropod shell 

fragments (Tye, 1989). These sandstones are interpreted as 

deposits from distributary-mouth bars and tidal and estuarine 

channels. Thinner sandstones with spiky log character are 

believed to have accumulated in tidal-fl at settings. Almost all 

of these sandstones are isolated within mudstones. 

Diagenesis of Sandstones 

of the Travis Peak Formation

Burial History

Following deposition, Travis Peak sediments experienced 

progressively deeper burial in eastern Texas until late midCretaceous time, when the Sabine arch was uplifted and eroded 

(Jackson and Laubach, 1991; Dutton and Diggs, 1992). Prior 

to this late mid-Cretaceous uplift, total burial depth and depth 

from surface were identical because Travis Peak strata were 

essentially horizontal. As renewed burial commenced in Late 

Cretaceous time, the Travis Peak was buried less deeply on the 

fl anks of the Sabine uplift and more deeply in the adjacent salt 

basins. Burial continued into the early Tertiary when a second 

period of uplift and erosion resulted in removal of 1,500 ft of 

section across most of northeastern Texas (Jackson and Laubach, 1991; Dutton and Diggs, 1992). Consequently, maximum 

burial depth for the Travis Peak at any given locale in northeastern Texas is 1,500 ft greater than present burial depth. 

Sandstone Composition

In northeastern Texas, most Travis Peak sandstones are 

fi ne-grained to very fi ne grained quartz arenites and subarkoses. Average framework composition is 95 percent quartz, 

4 percent feldspar, and 1 percent rock fragments (Dutton and 

Diggs, 1992). Dutton and Diggs (1992) defi ned clean sandstones as those with less than 2 percent detrital clay matrix. 

The average grain size of clean fl uvial sandstones is 0.15 mm 

as compared to 0.12 mm for clean paralic sandstones.

14 Geologic Studies of Basin-Centered Gas Systems
Compaction and Cementation

In northeastern Texas, Travis Peak sandstones have had 

a complex diagenetic history involving (1) mechanical compaction, (2) precipitation of cements and authigenic minerals, including dolomite, quartz, illite, chlorite, and ankerite, 

(3) generation of secondary porosity through dissolution of 

feldspar, and (4) formation of reservoir bitumen (Dutton and 

Diggs, 1992). Loss of primary sandstone porosity in nearsurface settings following deposition was negligible in most 

fl uvial sandstones. Minor loss of porosity occurred in paralic 

sandstones from precipitation of dolomite cement. From surface to a burial depth of about 3,000 ft, Travis Peak sandstones 

lost primary porosity mainly though mechanical compaction. 

Potential further compaction was halted by extensive quartz 

cementation that occurred between burial depths of 3,000 and 

5,000 ft. The next signifi cant diagenetic event was the creation 

of secondary porosity through dissolution of feldspar. Additional minor porosity reduction occurred to a depth of 7,500 ft 

from precipitation of authigenic chlorite, illite, and ankerite. 

Sandstones on higher parts of the Sabine uplift did not experience further porosity reduction from cementation. However, 

in Travis Peak sandstones buried below 8,000 ft on the western fl ank of the uplift, a second episode of extensive quartz 

cementation occurred in which silica was generated from pressure solution associated with development of stylolites. 

Reservoir Bitumen

A late-stage diagenetic event that signifi cantly reduced 

porosity and permeability in some Travis Peak sandstones in 

northeastern Texas was the formation of reservoir bitumen 

(Dutton, Laubach, Tye, and others, 1991; Lomando, 1992). 

Reservoir bitumen is a solid hydrocarbon that lines and fi lls 

both primary and secondary pores in some Travis Peak sandstones. Formation of reservoir bitumen occurred after precipitation of quartz and ankerite cement (Dutton, Laubach, Tye, 

and others, 1991), and its occurrence is limited to sandstones 

within the upper 300 ft of the Travis Peak Formation, which 

are primarily paralic sandstones. Geochemical analyses suggest that reservoir bitumen formed from deasphalting of oil 

trapped in pores of upper Travis Peak sandstones (Rogers and 

others, 1974; Dutton, Laubach, Tye, and others, 1991). The 

oil probably was similar to oil currently being produced from 

some Travis Peak sandstone reservoirs in fi elds in northeastern 

Texas. According to Tissot and Welte (1978), deasphalting 

commonly occurs in medium to heavy oil when large amounts 

of gas dissolve into the oil. Gas that dissolves into an oil to 

cause deasphalting can be generated from thermal alteration of 

the oil itself, or from introduction of new gas from outside the 

reservoir. The level of kerogen maturity in mudstones interbedded with Travis Peak sandstone reservoirs suggests that 

oils in Travis Peak sandstones were subjected to temperatures 

suffi cient to generate gas internally (Dutton, 1987). 

Among sandstones in the upper Travis Peak that contain 

reservoir bitumen, average and maximum volumes of bitumen 

are 4 percent and 19 percent, respectively. Samples examined 

by Dutton, Laubach, Tye, and others (1991) that contain reservoir bitumen had an average porosity of 7.5 percent prior to 

formation of bitumen. Formation of reservoir bitumen reduced 

that average porosity to 3.5 percent, a loss of 55 percent of 

the pre-bitumen pore space. Within the paralic facies, where 

most of the reservoir bitumen occurs, permeability patterns 

probably controlled the pore spaces into which oil originally 

migrated and in which reservoir bitumen eventually formed. 

Crossbedded and rippled sandstones that are clean and wellsorted contain large volumes of reservoir bitumen, whereas 

burrowed, shaly, poorly sorted sandstones have little or no reservoir bitumen. Consequently, many sandstone intervals that 

had the highest porosity and permeability following compaction and cementation now have little or no porosity because of 

formation of reservoir bitumen. 

Dutton, Laubach, Tye, and others (1991) provide a specifi c example that demonstrates the deleterious effect of reservoir bitumen on porosity, permeability, and wireline-log measurement of porosity. They describe a Travis Peak sandstone 

that has no reservoir bitumen from a depth of 8,216.5 ft in a 

particular well as having 11.6 percent porosity as measured 

by porosimeter, in-situ permeability of 22.5 mD, and average 

grain density of 2.65 g/cm3. Less than 1 ft below, at 8,217.2 

ft, the sandstone contains reservoir bitumen and has porosimeter porosity of 5.4 percent, permeability of 0.0004 mD, and 

average grain density of 2.51 g/cm3. Not only does reservoir 

bitumen signifi cantly reduce porosity and permeability, but it 

dramatically affects porosity measurements from a neutrondensity log. Although porosimeter porosity in the sandstone at 

8,217.2 ft was measured as 5.4 percent, porosity determined 

from a neutron-density log was 13 percent. Overestimation of 

porosity with a neutron-density log occurs because (1) density 

of reservoir bitumen is approximately the same as density of 

drilling-mud fi ltrate, which penetrates sandstone pores during 

drilling, and (2) 90 to 99 percent of reservoir bitumen is measured as porosity by a neutron log because of the hydrogen 

content of the bitumen. 

Porosity

Porosity and permeability of Travis Peak reservoir 

sandstones are controlled directly by diagenetic factors 

described above. Most hydrocarbon production from Travis 

Peak sandstones in northeastern Texas is from drilling depths 

between 6,000 and 10,000 ft, and sandstone porosity decreases 

signifi cantly with depth through that interval (Dutton and 

Diggs, 1992). Average porosity of clean Travis Peak sandstones decreases from 16.6 percent at 6,000 ft to 5.0 percent 

at 10,000 ft. For all Travis Peak sandstones (clean and shaly), 

average porosity decreases from 10.6 percent at 6,000 ft to 

4.4 percent at 10,000 ft (fi g. 7). Decrease in porosity from 

6,000 to 10,000 ft is not caused by increased compaction 

(Dutton, Laubach, Tye, and others, 1991; Dutton and Diggs, 

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 15
1992). Decrease in porosity with depth results primarily from 

(1) increasing amount of quartz cement, and (2) decrease in 

amount of secondary porosity. Secondary porosity was generated almost exclusively from dissolution of feldspar, and 

original feldspar content of Travis Peak sandstones decreases 

systematically with depth (Dutton and Diggs, 1992). High 

initial porosity together with high degree of connectivity of 

multilateral, multistory, braided-channel sandstones permitted 

large volumes of diagenetic fl uids to move through the thick 

Travis Peak fl uvial-sandstone sequence. As a result, the thick 

fl uvial section lost most of its primary porosity to extensive 

quartz cementation. However, because sandstones in the upper 

300 ft of the Travis Peak are encased in mudstones, smaller 

volumes of diagenetic fl uids moved through those sandstones, 

and they commonly retain signifi cant primary porosity (Dutton 

and Land, 1988). 

Within Travis Peak fl uvial-sandstone reservoirs at North 

Appleby fi eld, Tye (1991) reported that the greatest thickness 

of porous sandstone generally occurs in the widest portions of 

channel belts, and the highest porosities occur within 3 to 5 ft 

upward from the base of channels.

Permeability

According to Dutton and Diggs (1992), average stressed 

permeability of clean Travis Peak sandstones in northeastern 

Texas decreases by four orders of magnitude, from 10 mD at 

6,000 ft to 0.001 mD at 10,000 ft. For all sandstones, average stressed permeability declines from 0.8 mD at 6,000 ft 

to 0.0004 mD at 10,000 ft (fi g. 8). Decrease in permeability 

from 6,000 to 10,000 ft primarily is a function of (1) decrease 

r = 0.56

n = 1687

= 95 percent

confidence limit

0 10 100

Porosimeter porosity (percent)

5000

6000

7000

8000

9000

10000

11000

Depth (feet)

Depth (kilometers)

2

3

Figure 7. Semi-log plot of porosimeter porosity versus depth for 1,687 Travis Peak Formation sandstone samples from wells in eastern Texas (from Dutton, Laubach, Tye, and others, 1991). Samples 

include both clean and shaly sandstones. 

16 Geologic Studies of Basin-Centered Gas Systems
in porosity, which in turn is caused principally by increasing 

quartz cement, and (2) increasing overburden pressure that 

closes narrow pore throats. Although this latter effect has a signifi cant impact on permeability, it has little effect on porosity. 

At any given depth within the Travis Peak Formation in 

northeastern Texas, permeability ranges over approximately 

four orders of magnitude. Also, at any given depth, average 

permeability is 10 times greater in clean, fl uvial sandstones 

than in clean, paralic sandstones. According to Dutton and 

Diggs (1992), inferior permeability of clean, paralic sandstones probably can be attributed to three factors. First, 

because paralic sandstones are fi ner grained, they had poorer 

permeability than coarser grained fl uvial sandstones at the 

time of deposition. Second, although paralic sandstones and 

fl uvial sandstones contain similar amounts of quartz cement, 

paralic sandstones contain an average of 7 percent more total 

cement because they have signifi cantly larger volumes of 

authigenic dolomite, ankerite, illite and chlorite, as well as 

more reservoir bitumen. Third, much of the porosity in paralic 

sandstones is secondary porosity and microporosity associated 

with authigenic illite and chlorite that occurs within secondary 

pores. Secondary porosity and microporosity both contribute 

signifi cantly less to permeability than does primary porosity, 

in which pores are better connected.

Hydrocarbon Production

Although clean, paralic Travis Peak Formation sandstones have an order of magnitude poorer permeability than 

clean, fl uvial sandstones at any given depth, most hydrocarr = 0.63

n = 649

= 90 percent

confidence limit

.00001 .0001 1000 .001 .01 0.1 1 10 100

Stressed permeability (mD)

5000

6000

7000

8000

9000

10000

11000

Depth (feet)

Depth (kilometers)

2

3

Figure 8. Semi-log plot of stressed permeability versus depth for 649 Travis Peak Formation sandstone samples from wells in eastern Texas (from Dutton, Laubach, Tye, and others, 1991). Samples 

include both clean and shaly sandstones. Note that in addition to decrease in permeability with depth, 

permeability also varies by four orders of magnitude at any given depth. 

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 17
bon production from the Travis Peak in eastern Texas has 

come from paralic and high-sinuosity fl uvial sandstones in 

the upper 300 ft of the formation (Fracasso and others, 1988; 

Dutton, Laubach, Tye, and others, 1991; Dutton and others, 

1993). Concentration of producible hydrocarbons in sandstones in the upper part of the formation probably results 

from the absence of effective traps and seals in the underlying sandstone-rich, low-sinuosity fl uvial sequence. Multistory and multilateral fl uvial-channel belts within the fl uvial 

sequence afford a highly interconnected network of channel 

sandstones that provides effective migration pathways for 

hydrocarbons. Additionally, hydrocarbon migration through 

this sandstone network is enhanced by the presence of natural 

fractures, which are signifi cantly more abundant in the quartzcemented, sandstone-rich, low-sinuosity fl uvial sequence than 

in overlying paralic sandstones (Dutton, Laubach, Tye, and 

others, 1991). Consequently, hydrocarbons migrating upward 

into the Travis Peak Formation may have passed through the 

sandstone-rich fl uvial section before being trapped within 

upper Travis Peak paralic and high-sinuosity, fl uvial sandstones, which are encased in mudstones that provide effective 

hydrocarbon seals. Main reservoirs within the paralic sequence 

include tidal-channel and tidal-fl at sandstones along with highsinuosity, fl uvial-channel sandstones deposited in coastal-plain 

settings (Tye, 1989; Dutton, Laubach, and Tye, 1991)

Most Travis Peak hydrocarbon production comes from 

(1) structural, combination, or stratigraphic traps associated 

with low-relief closures or structural noses on the crest and 

fl anks of the Sabine uplift, and (2) structural or combination 

traps associated with salt structures in the East Texas and 

Northern Louisiana Salt Basins (Kosters and others, 1989; 

Dutton, Laubach, and Tye, 1991). Combination and stratigraphic traps occur where fl uvial sandstones pinch out into 

fl ood-plain mudstones or where paralic sandstones pinch out 

into tidal-fl at, estuarine, or shallow-marine mudstones across 

closures, noses, or on regional dip. 

According to Fracasso and others (1988), wells on the 

western fl anks of structures in northeastern Texas generally 

require hydraulic-fracture treatments to produce commercially 

from Travis Peak sandstone reservoirs, whereas wells on the 

eastern fl anks typically fl ow gas at commercial rates without 

stimulation. These trends refl ect a general east-to-west deterioration in Travis Peak sandstone porosity and permeability across 

structures. These east-west patterns in reservoir quality of upper 

Travis Peak paralic sandstones are not related to depositional 

facies changes. According to Fracasso and others (1988), these 

patterns are attributed to control by structures on regional fl ow of 

diagenetic fl uids; this resulted in cementation being fostered on 

western fl anks, or inhibited on eastern fl anks, or both. 

Source Rocks

In a study of diagenesis and burial history of the Travis 

Peak Formation in eastern Texas, Dutton (1987) showed that 

shales interbedded with Travis Peak sandstone reservoirs were 

deposited in fl uvial-deltaic settings where organic matter commonly was oxidized and not preserved. With measured values 

of total organic carbon (TOC) in Travis Peak shales generally 

less than 0.5 percent, these shales would not be considered as 

potential hydrocarbon source rocks, according to Tissot and 

Welte (1978). Dutton (1987) suggested that the most likely 

sources for hydrocarbons in Travis Peak reservoirs in eastern 

Texas are (1) prodelta and basinal marine shales of the Jurassic Bossier Shale, basal formation of the Cotton Valley Group, 

and (2) laminated, lime mudstones of the lower member of 

the Jurassic Smackover Formation (fi g. 3). Sassen and Moore 

(1988) demonstrated that Smackover carbonate mudstones 

are a signifi cant hydrocarbon source rock in Mississippi and 

Alabama. Wescott and Hood (1991) documented the Bossier 

Shale as a major source rock in eastern Texas. Presley and 

Reed (1984) suggested that gray to black shales interbedded 

with Cotton Valley sandstones could be a signifi cant source 

for gas as could the underlying Bossier Shale. In summary, 

despite limited source-rock data, it seems likely that signifi -

cant hydrocarbon source rocks occur in the Bossier Shale of 

the Cotton Valley Group, which underlies the Travis Peak Formation, and also in stratigraphically lower Smackover carbonate mudstones (fi g. 2).

Burial and Thermal History

Vitrinite refl ectance (Ro) is a measure of thermal maturity of source rocks based on diagenesis of vitrinite, a type 

of kerogen derived from terrestrial woody plant material. In 

studying diagenesis and burial history of the Travis Peak Formation in eastern Texas, Dutton (1987) reported that measured 

Ro values for Travis Peak shales generally range from 1.0 to 

1.2 percent, indicating that these rocks have passed through 

the oil window (Ro = 0.6 to 1.0 percent), and are approaching the level of onset of dry-gas generation (Ro = 1.2 percent) 

(Dow, 1978). Maximum Ro of 1.8 percent was measured in the 

deepest sample from a downdip well in Nacogdoches County, 

Texas. Despite relatively high thermal maturity levels reached 

by Travis Peak shales, the small amount and gas-prone nature 

of organic matter in these shales precludes generation of oil, 

although minor amounts of gas might have been generated 

(Dutton, 1987). 

In the absence of actual measurements of Ro, values 

of Ro can be estimated by plotting burial depth of a given 

source rock interval versus time in conjunction with an 

estimated paleogeothermal gradient (Lopatin, 1971; Waples, 

1980). Dutton (1987) presented burial-history curves for 

the tops of the Travis Peak, Cotton Valley, Bossier, and 

Smackover for seven wells on the crest and western fl ank 

of the Sabine uplift. The burial-history curves show total 

overburden thickness through time and use present-day compacted thicknesses of stratigraphic units. Sediment compaction through time was considered insignifi cant because of 

18 Geologic Studies of Basin-Centered Gas Systems
absence of thick shale units in the stratigraphic section. Loss 

of sedimentary section associated with late mid-Cretaceous 

and mid-Eocene erosional events was accounted for in the 

burial-history curves. 

Dutton (1987) provided justifi cation for using the average present-day geothermal gradient of 2.1°F/100 ft for the 

paleogeothermal gradient for the fi ve northernmost wells. 

Paleogeothermal gradients in the two southern wells probably 

were elevated temporarily because of proximity to the area of 

initial continental rifting in the Triassic. Based on the crustal 

extension model of Royden and others (1980), Dutton (1987) 

estimated values for elevated paleogeothermal gradients for 

these two wells for 80 m.y. following the onset of rifting; after 

that, the value reverts to the present-day gradient for the past 

100 m.y.

Using estimated paleogeothermal gradients in conjunction with burial-history curves, Dutton (1987) found that calculated values of Ro for Travis Peak shales agree well with 

measured values. Because of this agreement, Dutton (1987) 

used the same method to calculate Ro values for tops of the 

Cotton Valley, Bossier, and Smackover in eastern Texas. Estimated Ro values for the Bossier Shale and Smackover in seven 

wells range from 1.8 to 3.1 percent and 2.2 to 4.0 percent, 

respectively, suggesting that these rocks reached a stage of 

thermal maturity in which dry gas was generated. Assuming 

that high-quality, gas-prone source rocks occur within these 

two formations, it is likely that one or both of these units 

generated gas found in Travis Peak reservoirs. 

No such regional source-rock and thermal-maturity 

analysis is known for the Travis Peak (Hosston) Formation in 

northern Louisiana. Scardina (1981) presented burial-history 

data for the Cotton Valley Group but included no information 

on geothermal gradients and thermal history of rock units. 

Present-day reservoir temperatures in Travis Peak sandstones 

of both eastern Texas and northern Louisiana range from 200° 

to 250°F (table 1). It is likely that Bossier and Smackover 

source rocks in northern Louisiana have experienced a thermal 

history relatively similar to their stratigraphic counterparts 

in eastern Texas and, therefore, may be sources for Travis 

Peak gas in northern Louisiana. Herrmann and others (1991) 

presented a burial-history plot for Ruston fi eld in northern 

Louisiana. At Ruston fi eld, they suggested that Smackover 

gas was derived locally from Smackover lime mudstones and 

Cotton Valley gas from Cotton Valley and Bossier shales. 

Their burial-history plot shows that onset of generation of gas 

from Smackover and Cotton Valley source rocks at Ruston 

fi eld occurred about 80 Ma and 45 Ma, respectively. These 

estimates are reasonably consistent with Dutton’s (1987) date 

of 57 Ma for onset of generation of dry gas from the Bossier 

Shale in eastern Texas. Most salt structures in the East Texas 

Salt Basin were growing during Travis Peak deposition 

(McGowen and Harris, 1984) and presumably they were growing in the Northern Louisiana Salt Basin, as well. Therefore, 

these structures would have provided traps for hydrocarbons 

generated from Smackover, Bossier, and Cotton Valley source 

rocks. Also, as noted earlier in this report, the Sabine uplift has 

been a positive feature for the past 60 m.y. (Kosters and others, 

1989; Jackson and Laubach, 1991). It therefore would have 

been a focal area for gas migrating from Smackover, Bossier, 

and Cotton Valley source rocks in the East Texas and Northern 

Louisiana Salt Basins.

Abnormally Pressured Reservoirs

Pore pressure or reservoir pressure commonly is reported 

as a fl uid-pressure gradient (FPG) in pounds per square 

inch/foot (psi/ft). The normal FPG is 0.43 psi/ft in freshwater reservoirs and 0.50 psi/ft in reservoirs with very saline 

waters (Spencer, 1987). In his study of abnormally high pressure gradients in basin-centered gas accumulations in Rocky 

Mountain basins, Spencer (1987) considered reservoirs to be 

signifi cantly overpressured if FPGs exceed 0.50 psi/ft where 

waters are fresh to moderately saline, and exceed 0.55 psi/ft 

where waters are very saline. With formation-water salinity 

of Travis Peak sandstone reservoirs about 170,000 parts per 

million (ppm) total dissolved solids (TDS) (Dutton and others, 

1993), salinity is considered high, and these reservoirs should 

be considered to be signifi cantly overpressured if their FPGs 

exceed 0.55 psi/ft.

FPGs for Travis Peak sandstone reservoirs for various oil 

and gas fi elds in northeastern Texas and northern Louisiana 

(table 1; fi gs. 9 and 10) were calculated from initial shut-in 

pressures reported in Herald (1951), Shreveport Geological 

Society Reference Reports (1946, 1947, 1951, 1953, 1958, 

1963, 1987), Kosters and others (1989), Shoemaker (1989), 

and Bebout and others (1992). Multiple FPG values for a 

specifi c fi eld (fi gs. 9 and 10; table 1) refer to FPGs calculated 

for different, stacked Travis Peak sandstone reservoirs in that 

fi eld. Most calculated FPGs are between 0.41 and 0.49 psi/ft 

(table 1; fi gs. 9 and 10). Higher FPGs were encountered in 

three fi elds in northeastern Texas (fi g. 9): 0.53 psi/ft at TriCities and Percy-Wheeler fi elds, and 0.54 psi/ft at Carthage 

fi eld. A gradient of 0.79 psi/ft was calculated for one Travis 

Peak sandstone reservoir in Clear Branch fi eld in northern 

Louisiana, although gradients in three other Travis Peak reservoirs within that same fi eld were 0.47, 0.48, and 0.48 psi/ft 

(table 1, fi g. 10). A number of other fi elds scattered geographically across northeastern Texas and northern Louisiana exhibit 

below-normal FPGs ranging from 0.36 to 0.38 psi/ft. The 

lowest FPG in the Travis Peak fi eld trend is 0.27 psi/ft in Village fi eld, Columbia County, Arkansas (table 1; fi g. 10). 

In northern Louisiana where Travis Peak hydrocarbon production comes from various interdeltaic sandstones 

throughout the Travis Peak section, shut-in-pressure data are 

available from a variety of depths. In northeastern Texas, 

however, most production comes from sandstone reservoirs 

in the upper 300 ft of the Travis Peak Formation. Consequently, shut-in-pressure data are abundant for the upper 300 

to 500 ft of the Travis Peak, but data are limited in the lower 

three-fourths of the formation, which include the thick fl uvial 

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 19
Table 1 (below and on facing page). Data for Travis Peak Formation fields in Texas, Louisiana, and Arkansas. 

[Data primarily from Shreveport Geological Society Reference Reports, Herald (1951), Kosters and others (1989), Shoemaker (1989), and Bebout and others 

(1992). Field, name of field producing from Travis Peak sandstones; Discovery date, date of discovery of oil or gas in particular Travis Peak sandstone; Trap, 

trapping mechanism for field (Struct, structural trap; Strat, stratigraphic trap; Comb, combination structural and stratigraphic trap; A, anticline; FA, faulted 

anticline; FC, facies change (sandstone pinch-out); N, structural nose; FN, faulted structural nose); Depth, depth, in feet, to particular productive Travis Peak 

sandstone reservoir; Porosity, sandstone porosity (decimal); BHT, bottom-hole temperature (°F); BHP, bottom-hole pressure (psi); FPG, Fluid-pressure gradient

(psi/ft); Sw, water saturation (decimal); Fluid contacts, gas-oil, oil-water, and gas-water contacts (GOC, gas-oil contact; OWC, oil-water contact; GWC, gaswater contact); IP, initial production rate for specific Travis Peak sandstone reservoirs (MCFD, thousand cubic feet per day (gas)); BOPD, barrels of oil per day;

BCPD, barrels of condensate per day; BWPD, barrels of water per day; avg, average of values; N. res., north reservoir; S. res., south reservoir; Pos., position of 

reservoir within Travis Peak Formation (L, lower; U, upper; uL, upper part of lower); Ext., extension. Blank spaces indicate no data] 

Field County State Discovery Trap Depth Porosity Permeability BHT 

 date (feet) (decimal) (mD) (°F) 

Appleby North Nacogdoches TX Strat (FC) 8,872 0.11 0.015 (avg) 254 

Bethany Panola, Harrison TX 1940 Comb (FA, FC) 6,024 

 1948 6,300 0.15 115 206 

Blackfoot Anderson TX 1948 Comb (A, FC) 9,918 

Carthage Panola TX 1942 Struct (A) 6,128 

1944 6,439 

 1945 6,230 0.15 10.8 

Cedar Springs Upshur TX 1967 Struct (A) 8,960 0.10 240

Chapel Hill Smith TX 1947 Comb (A, FC) 

Cyril Rusk TX 1963 Strat (FC) 7,650 0.09–0.18 <1 to 200 200

Danville Rusk TX 1959 Comb (FA, FC) 7,606 

Henderson Rusk TX 1950 Struct (A) 7,457 0.18 72 185

Henderson South Rusk TX 1946 Struct (A) 

Joaquin Shelby TX 1968 Struct (A) 6,300 

Lansing North Harrison TX 1950 Struct (A) 7,606 

Lassater Marion TX 1948 Struct (A) 9,035 

Longwood Harrison TX 1948 Comb (N, FC) 

McBee Leon TX 1955 Comb (N, FC) 10,100 0.07–0.10 216

Minden Rusk TX 1953 Comb (N, FC) 7,372 

Opelika Henderson, Van Zandt TX 1944 Strat (FC)? 

Percy Wheeler Cherokee TX Gas 1979 Comb (FN, FC) 9,100 0.10 (avg) 0.076 (avg) 245 

Oil 1980 Comb (FN, FC) 9,159 

Pinehill Southeast Rusk, Panola TX Strat (FC) 7,155 0.08 1.3 (avg) 199 

Pokey Limestone TX 1959 Strat (FC) 7,084 0.08–0.20 190

Reed Freestone TX 1945 

Rischers Store Freestone TX 1967 Comb (A, FC) 7,236 0.10–0.23 240

Teague West Freestone TX 1951 Comb (FC, FA) 7,680 

Trawick Nacogdoches, Rusk TX 1963 Comb (A, FC) 8,561 0.08–0.12 0.1 (avg) 

Tri-Cities Henderson TX 1950 Comb (FC, FA) 8,496 0.10 0.01 to 85 240 

Waskom Harrison TX 1939 Comb (A, FC) 6,185 

 1973 7,404 0.17 65 198 

Whelan Harrison TX 1946 Comb (FC, FA) 8,036 0.13 0.05 to 83 220

White Oak Creek Cherokee TX 1976 Srtuct (FA) 10,024 

Willow Springs Gregg TX 1954 Struct (A) 7,812 0.13 20 (1.48 avg) 229

Woodlawn Harrison TX 

Ada-Sibley Webster LA 1951 Struct (FA) 6,900 0.19 131 

Arcadia Bienville LA 1965 Srtuct (FA) 7,050 

Athens Claiborne LA 1941 Comb (FA, FC) 6,172 

1943 6,400 

 1948 7,240 

1949 7,696 

 1949 6,314 

Bear Creek-Bryceland Bienville LA 1937 Comb (A, FC) 7,240 0.16 170

Bethany-Longstreet DeSoto, Caddo LA 1954 Struct (A) 7,000 

Bryceland West Bienville LA 1952 Comb (FA, FC) 6,900 

Calhoun Ouachita LA 1936 Comb (FA, FC) 6,900 

20 Geologic Studies of Basin-Centered Gas Systems
Table 1. Data for Travis Peak Formation fields in Texas, Louisiana, and Arkansas—Continued.

BHP FPG Pos Sw Fluid contacts IP IP IP IP 

(psi) (psi/ft) (MCFD) (BOPD) (BCPD) (BWPD) 

3,890 0.44 L 0.28 

2,295 0.38 U 60,000 720

3,113 0.49 uL 0.34 

U Elevation of bottom of oil –9,589 63

 Lenticular sandstones w/ complex GWCs 5,900 147.5 

26.7 

3,350 0.54 U 0.24 

4,409 0.49 L 0.30 

 U Elevation of bottom of gas –7835 

3,550 0.46 U 0.25 to 0.55 OWC –7,125 N. res.; GOC –7,100, OWC –7,125 S. res. 20

 

3,186 0.43 U 0.26 GOC –6,995; OWC –7,005 1,500 49

 U Elevation of bottom of gas –7,020 655 13 

 Lowest gas –7,314 2,100 

Lowest gas –8,730 2,540 243.7 

 Lowest gas –5,754 

3,625 0.36 U 0.31 to 0.38 1,650 

 

4,843 0.53 U 0.33 3,200 

180 62 23

3,071 0.43 U 0.42 

3,250 0.46 U 0.36 to 0.45 4,700 

 U Elevation of bottom of gas –7,860 

3,000 0.41 U < 0.45 1,900 43

 

3,720 0.43 uL 0.20 to 0.45 7,600 

4,500 0.53 U 0.32 

U GWC –5,880 5,040 

2,795 0.38 L 

3,076 0.38 uL

 

3,421 0.44 uL

 8,000 192 

4,000 20

 11,600 23 

118

 68 

Multiple sands with separate GWCs 5,000 to 165,000 

 Flank wells tested water without gas 

 

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 21
Table 1 (below and on facing page). Data for Travis Peak Formation fields in Texas, Louisiana, and Arkansas—Continued.

Field County State Discovery Trap Depth Porosity Permeability BHT 

 date (feet) (decimal) (mD) (°F) 

Caspiana DeSoto, Caddo LA 

Chatham Jackson LA 1945 9,620 

Chenier Creek Ouachita LA 1949 Comb (N, FC) 7,782 0.16 6 211 

Choudrant Lincoln LA 1959 Struct (A) 8,568 0.19 250

Clay Lincoln LA 1958 Struct (A) 7,305 

Clear Branch Jackson LA 1975 Comb (N, FC) 9,000 0.07 3.8 191

 10,000 0.08 1.4 205 

10,100 0.07 0.6 218

 11,900 0.05 0.3 282 

Cotton Plant Caldwell LA 1984 Comb (N, FC) 10,200 0.15 166 258

 10,600 0.13 272 

Cotton Valley Webster LA 1936 Struct (A) 5,550 

Danville Bienville LA 1966 Struct (A) 7,700 

Downsville Union LA 1948 Comb (A, FC) 7,390 

 1962 Comb (A, FC) 7,819 

1978 Comb (A, FC) 7,652 0.17 177

Driscoll Bienville LA 1937 Struct (A) 7,200 

Elm Grove Bossier LA 1975 Struct (FA) 5,852 

Elm Grove (Ext.) Caddo, Bossier LA 1984 Struct (FA) 5,956 

Hico-Knowles Lincoln LA 1959 Comb (A, FC) 6,600 

Hodge Jackson LA 1961 Struct (A) 7,900 

Holly DeSoto LA 1974 Strat (FC) 7,000 

Leatherman Creek Claiborne LA 1975 Comb (FA, FC) 8,387–9,614 0.10 0.7 215 

Lisbon Claiborne LA 1941 Strat (FC) 5,100 0.23 500

Lisbon North Claiborne LA 1941 Struct (A) 5,112 

Lucky Bienville LA 1943 Struct (FA) 7,900 0.15 

Ruston Lincoln LA 1943 Comb (A, FC) 5,896 

1944 5,745 

Sailes Bienville LA 1945 Comb (FA, FC) 8,847 0.14 

Shreveport Caddo, Bossier LA 1951 Struct (A) 6,238 

Simsboro Lincoln LA 1936 Struct (FA) 6,571 0.22 500 

1951 Struct (FA) 8,069 0.15 2 to 50 

Sugar Creek Claiborne LA 1936 Comb (FA, FC) 5,600 0.19 65 

1937 5,718 

Vixen Caldwell LA 1945 Struct (A) 9,700 

Waskom Caddo LA Comb (A, FC) 

Village Columbia AR 1946 Struct (A) 4,800 0.26 706 

sequence that characterizes the bulk of the Travis Peak in 

northeastern Texas. Calculated FPGs from sandstone reservoirs at depths of 500 or more ft below the top of the Travis 

Peak are normal at North Appleby, Bethany, Cedar Springs, 

and Trawick fi elds and subnormal at Waskom and Whelan 

fi elds (table 1, fi g. 9). Reservoirs in the middle and lower 

Travis Peak section at Woodlawn and Carthage fi elds also are 

normally pressured, according to Al Brake (BP Amoco engineer, oral commun., 2000), who reports no knowledge of any 

signifi cant overpressure in Travis Peak reservoirs at any depth 

within the formation in northeastern Texas. The best available 

data, therefore, suggest that Travis Peak reservoirs are not signifi cantly overpressured in northeastern Texas. 

Hydrocarbon-Water Contacts

Based on data for various Travis Peak oil and gas fi elds 

reported primarily by the Shreveport Geological Society 

(1946, 1947, 1951, 1953, 1958, 1963, 1987), East Texas Geological Society (Shoemaker, 1989), and Texas Bureau of Economic Geology (Herald, 1951), hydrocarbon-water contacts 

have been documented in Travis Peak sandstone reservoirs in 

13 fi elds across eastern Texas and northern Louisiana (fi gs. 11 

and 12). Field reports edited by Herald (1951) do not use the 

terms “gas-water contact” or “oil-water contact” but do report 

“elevation of bottom of oil or gas” and “lowest oil or gas.” It 

22 Geologic Studies of Basin-Centered Gas Systems
seems likely that “lowest gas” refers to the lowest elevation 

gas had been encountered by drilling at the time the report 

was written, whereas “elevation of bottom of gas” refers to an 

actual gas/water contact. Supporting that interpretation is the 

fact that the term “elevation of bottom of gas” clearly was used 

to indicate elevation of a gas-oil contact at Henderson fi eld 

(Herald, 1951). If this interpretation of “elevation of bottom 

of gas” is correct, hydrocarbon-water contacts are documented 

in Travis Peak sandstone reservoirs in four additional fi elds 

(Herald, 1951), as indicated in table 1 and shown by dashed 

fi eld outlines in fi gure 11. 

Most Travis Peak production in northeastern Texas comes 

from the upper 300 ft of the formation, and hydrocarbon-water 

contacts documented in Travis Peak sandstone reservoirs 

in the seven Texas fi elds (table 1; fi g. 11) all occur within 

reservoirs in that upper part of the formation. No documentation of hydrocarbon-water contacts in middle or lower Travis 

Peak reservoirs in northeastern Texas has been found. At 

North Appleby fi eld, Nacogdoches County, Texas, Tye (1991) 

reported that gas seems to be present throughout the Travis 

Peak section, though not necessarily in commercial amounts, 

and a discrete gas-water contact does not exist within the 

Travis Peak. 

An attempt was made to document the presence or 

absence of hydrocarbon-water contacts in additional Travis 

Peak fi elds through analysis of data from drill-stem tests 

Table 1. Data for Travis Peak Formation fields in Texas, Louisiana, and Arkansas—Continued.

BHP FPG Pos Sw Fluid contacts IP IP IP IP 

(psi) (psi/ft) (MCFD) (BOPD) (BCPD) (BWPD) 

 Flank wells tested water without gas 

3,700 0.38 8,000 

3,050 0.39 0.34 Flank wells tested water without gas 2,700 2.7 0 

 

4,190 0.47 0.53 4,088 2

4,785 0.48 0.37 

4,865 0.48 0.38 

9,450 0.79 0.31 

4,884 0.48 GWC –10,163 & –10,592 3,803 

5,078 0.48 4,569 

240

 

3,375 0.46 4,093 4.5

3,840 0.49 4,100 16.4 

3,550 0.46 0.25 GWC –7,441 2,000 6

 25,000 

2,739 0.46 2,675 0 

 

 0.47 0.30 5,585 24 

 3,840 56 

2,800 0.35 2,000 

2,400 0.41 Multiple sands with separate GWCs 45,000 

25,000 

 0.3 432 

2,080 

 Multiple sands with separate GWCs 67,634 

16,500 

2,300 0.41 20,000 

Multiple sands with separate GWCs & OWCs 205

3,600 0.37 9,000 

1,300 0.27 

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 23
(DSTs) and production tests. The goal was to determine 

if fi elds that produce gas from Travis Peak sandstones are 

fl anked by dry holes that tested water only without gas, indicative of presence of a gas-water contact. A data set of wells 

penetrating the Travis Peak and Cotton Valley Group across 

much of northeastern Texas and northern Louisiana was 

extracted from a database provided by IHS Energy Group 

(petroROM Version 3.43) for analysis of DST and production-test data using ArcView software (Environmental Systems 

Research Institute, Inc., version 3.2). Well data were sorted 

and displayed in map view using ArcView software such that 

wells that produce from Travis Peak sandstones could be distinguished from Travis Peak dry holes with tests. While viewing the map display, we could examine test results from any 

particular well. 

Reconnaissance analysis of test data show that water was 

recovered without gas from production tests or DSTs in Travis 

Peak sandstone reservoirs in wells on one or more fl anks of 

Bethany-Longstreet, Cheniere Creek, and Caspiana fi elds in 

northern Louisiana (fi g. 12). These data indicate presence of 

gas-water contacts within Travis Peak sandstone reservoirs in 

those fi elds.

In summary, hydrocarbon-water contacts have been documented in Travis Peak sandstone reservoirs at various depths 

within the formation in northern Louisiana and within the 

upper 300 ft of the formation in northeastern Texas. Although 

data from the middle and lower Travis Peak section in northeastern Texas are limited, no hydrocarbon-water contacts have 

been reported from that interval in northeastern Texas.

Discussion of Evidence 

For and Against Basin-Centered Gas

Source Rocks and Burial and Thermal History

Source rocks responsible for generating gas in 

basin-centered gas accumulations commonly are in stratiAngelina

Nacogdoches

Houston

Rockwall

0 20 40 Miles 10 30

TEXAS

LOUISIANA

AR

LA

Collin Hunt

Ellis

Navarro

Hill

Falls

Limestone Freestone

Leon

Anderson

Cherokee

Rusk

Smith

Henderson

Van Zandt

Gregg

Upshaw

Wood

Camp

Rains

Hopkins Franklin Titus

Morris Cass

Marion

Harrison

Miller

Caddo

De Soto

Shelby

Panola

Sabine

San Augustine

Hemphill

Dallas

Kaufman Gulf of Mexico

TX

LA

OK AR

DETAIL MS AL

AREA

LOCATION MAP

FLUID-PRESSURE GRADIENTS (PSI/FT)

TRI CITIES

0.53 PERCY

WHEELER

0.53

RISCHERS STORE

0.41

McBEE

0.36

POKEY

0.46

TRAWICK

0.43

APPLEBY

NORTH

0.44

CARTHAGE

0.54

0.43

PINEHILL

SOUTHEAST

HENDERSON

0.43

BETHANYLONGSTREET

0.38

0.49

WASKOM

0.38

0.44

WILLOW

SPRINGS

WHELAN

0.38

CEDAR SPRINGS

0.49

CYRIL

0.46

Figure 9. Map of northeastern Texas showing fl uid-pressure gradients (FPG) (psi/ft) calculated from original shut-in pressures in Travis Peak 

Formation sandstone reservoirs. Multiple pressure-gradient values for a particular fi eld are gradients calculated for different stacked sandstone 

reservoirs in that fi eld. Shut-in pressure data are shown in table 1 along with sources for those data. Underlined FPG values indicate those from 

depths 500 ft or deeper below top of Travis Peak Formation.

24 Geologic Studies of Basin-Centered Gas Systems
graphic proximity to low-permeability reservoirs that hold 

the gas. As described above, shales interbedded with Travis 

Peak sandstone reservoirs in northeastern Texas have passed 

through the oil window and are approaching the level of onset 

of dry-gas generation. However, these shales are primarily 

oxidized fl ood-plain shales with TOC content generally less 

than 0.5 percent, and therefore are not considered as potential 

hydrocarbon source rocks (Tissot and Welte, 1978; Dutton, 

1987). Dutton (1987) suggested that Travis Peak marine shales 

depositionally downdip from the Travis Peak hydrocarbon-productive trend probably have higher TOC content and thus might 

be potential source rocks. Because these marine shales occur 

primarily in Louisiana, Dutton (1987) expressed concern about 

long lateral migration distances that would be required to move 

hydrocarbons from these shales to updip Travis Peak sandstone 

reservoirs in eastern Texas. Dutton (1987) concluded that the 

marine Bossier Shale, which is the lowermost formation of 

the Cotton Valley Group, and Smackover laminated lime mudstones, which lie below the Bossier Shale (fi g. 2) are the source 

rocks most likely to have generated hydrocarbons produced 

from Travis Peak reservoirs in eastern Texas. Gray to black 

marine shales interbedded with Cotton Valley sandstones also 

might be potential source rocks. As discussed above, burial- and 

thermal-history data for the northern Gulf Coast Basin suggest 

that burial depths of Bossier and Smackover source rocks, in 

conjunction with the regional geothermal gradient, have been 

suffi cient to generate dry gas. Also, as described above, time of 

generation of most of this gas postdates development of both 

the Sabine uplift and structures in the East Texas and Northern 

Louisiana Salt Basins. Available data, therefore, provide a reasonable scenario for charging Travis Peak sandstone reservoirs 

with oil and gas. Postulated Bossier Shale source rocks, however, are separated stratigraphically from Travis Peak sandstone 

reservoirs by at least 1,000 ft of tight Cotton Valley sandstones 

and interbedded shales, and also by the tight Knowles Limestone across much of the area (fi g. 4). Potential Smackover 

source rocks are stratigraphically lower yet, and are separated 

from the Bossier by Haynesville/Buckner units, which include 

anhydrite. Although a reasonable scenario can be established 

for charging Travis Peak sandstone reservoirs with gas derived 

West

Carroll

East

Carroll

Kaufman

WASKOM

0.38

BETHANYLONGSTREET

0.38

0.49

ELM

GROVE

0.46

LEATHERMAN

CREEK

0.47

LUCKY

0.35

VILLAGE

0.27

CHENIERE

CREEK

0.39 CHATHAM

0.38

CLEAR BRANCH

0.47

0.48

0.48

0.79

VIXEN

0.37

COTTON PLANT

0.48

0.48

SUGAR

CREEK

0.41

DOWNSVILLE

0.46

0.49

0.46

RUSTON

0.41

Bossier

Miller

TEXAS

LOUISIANA

ARKANSAS

LOUISIANA

MISSISSIPPI

Cass Lafayette Columbia

Webster

Caddo

Marion

Harrison

Panola

Shelby

De Soto

Sabine

Natchitoches

Red River

Beinville

Lincoln

Jackson

Union

Union

Ashley

Morehouse

Chicot

Ouachita

Madison

Franklin

Tensas

Catahoula LaSalle

Grant

Concordia

Winn LOUISIANA

Caldwell

0 20 40 Miles 10 30

Dallas

Gulf of Mexico

TX

LA

OK AR

DETAIL MS AL

AREA

LOCATION MAP

FLUID-PRESSURE GRADIENTS (PSI/FT)

Richland

Claiborne

Figure 10. Map of northern Louisiana showing fl uid-pressure gradients (psi/ft) calculated from original shut-in pressures in Travis Peak 

Formation sandstone reservoirs. Multiple pressure-gradient values for a particular fi eld are gradients calculated for different stacked sandstone 

reservoirs in that fi eld. Shut-in pressure data are shown in table 1 along with sources for those data.

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 25
from stratigraphically lower source rocks, abundant gas-prone 

source rocks are not proximal to those reservoirs. This is not 

characteristic, in general, of classic basin-centered gas accumulations.

Porosity and Permeability

Continuous, basin-centered gas accumulations commonly 

involve a large volume of gas-saturated reservoir rock in 

which presence of gas cuts across stratigraphic units. Such gas 

accumulations require a regional seal to trap gas, and that seal 

characteristically is provided by the inherent low permeability 

of reservoir rocks themselves. Thus, continuous-gas reservoirs 

characteristically have low permeability, and when reservoirs 

are sandstones, they generally are referred to as tight-gas sandstones. 

As discussed in the Introduction, the Travis Peak Formation was selected by GRI as one of two low-permeability formations for comprehensive geologic and engineering studies 

under auspices of its Tight Gas Sands Program. Also, Travis 

Peak sandstones have been designated as “tight” by the Federal Energy Regulatory Commission (FERC) in selected areas 

of northeastern Texas, northern Louisiana, and in one well in 

Jefferson Davis County, Mississippi (Dutton and others, 1993). 

That Travis Peak sandstones have been designated “tight” only 

in selected areas and not universally across the northern Gulf 

Coast Basin, however, refl ects the relatively high permeability 

of Travis Peak sandstone reservoirs locally and signifi cant 

variation of permeability with depth (fi g. 8) and geographically across the northern Gulf Coast Basin (fi gs. 13 and 14). 

As shown in fi gure 8, permeability of Travis Peak sandstones in northeastern Texas varies signifi cantly with depth. 

Above 7,500 ft, numerous Travis Peak sandstone samples 

exhibit permeability values above 0.1 mD, the general permeability cutoff for designation as a tight-gas sandstone. At 

Houston

Ellis

Leon

Camp

Rains

Morris

Dallas

Kaufman

KNOWN FIELDS WITH TRAVIS PEAK FORMATION

HYDROCARBON-WATER CONTACTS

without gas from Travis Peak sandstones

Angelina

Nacogdoches

Rockwall

TEXAS

LOUISIANA

AR

LA

Collin Hunt

Navarro

Hill

Falls

Limestone Freestone

Anderson

Cherokee

Rusk

Smith

Henderson

Van Zandt

Gregg

Upshaw

Wood

Hopkins Franklin Titus

Marion

Harrison

Miller

Caddo

De Soto

Shelby

Panola

Sabine

San Augustine

Hemphill

CHAPEL HILL

BLACKFOOT

REED

HENDERSON

HENDERSON

SOUTH

CYRIL

BETHANYLONGSTREET

WASKOM

Gulf of Mexico

TX

LA

OK AR

DETAIL MS AL

AREA

LOCATION MAP

Cass

0 20 40 Miles 10 30

Hydrocarbon-water contacts reported in public literature

Gas-water contact inferred from flank wells that tested water

Field with probable hydrocarbon contacts based on meaning

of terms in Herald (1951)

CARTHAGE

Figure 11. Map of northeastern Texas showing fi elds in which hydrocarbon-water contacts have been identifi ed in Travis Peak Formation 

sandstone reservoirs. Dark shading indicates fi elds in which Travis Peak hydrocarbon-water contacts have been reported in publicly available 

literature (see table 1). Light shading indicates fi elds in which gas-water contacts are inferred based on presence of fl ank wells that tested 

water only, without gas, identifi ed from IHS Energy data (PI/Dwights Plus of Petroleum Information/Dwights, d.b.a. IHS Energy Group). Fields 

with dashed outlines are those that probably have gas-water or oil-water contacts, depending on meaning of terms “elevation of bottom of 

gas” and “elevation of bottom of oil,” as reported in Herald (1951) and discussed in this report. All Travis Peak hydrocarbon-water contacts in 

these fi elds occur within sandstone reservoirs in the upper 300 to 500 ft of the Travis Peak Formation.

26 Geologic Studies of Basin-Centered Gas Systems
depths less than 6,000 ft, permeability can exceed 100 mD. As 

discussed above, the decrease in permeability of Travis Peak 

sandstones by four orders of magnitude from 6,000 to 10,000 

ft in northeastern Texas is controlled primarily by the volume 

of quartz cement. Such variation with depth probably explains 

much of the apparent geographic variation in permeability of 

Travis Peak sandstones (fi gs. 13 and 14). Multiple values of 

permeability for a given fi eld refer to measurements from different, stacked Travis Peak sandstones within that fi eld. For 

many fi elds (fi gs. 13 and 14), a range of measured permeability values is given, probably refl ecting primarily variation of 

sandstone permeability with depth within those fi elds. Abundance of high-permeability sandstones, especially in upper 

portions of the Travis Peak Formation, is not characteristic of 

reservoirs that harbor basin-centered gas accumulations. This 

is because such higher permeability reservoirs cannot provide 

their own internal, albeit leaky, seal for gas. 

Although sandstones throughout the entire Travis Peak 

Formation reportedly are charged with gas in some Travis Peak 

fi elds, though not necessarily in commercial quantities (Davies 

and others, 1991; Tye, 1991; Dutton and others, 1993), gas production comes primarily from sandstones in the upper 300 ft of 

the formation (Fracasso and others, 1988; Al Brake, BP Amoco 

engineer, oral commun., 2000). To some degree, this might be 

a function of higher permeability of upper Travis Peak sandstones, which results in preferential completion of upper Travis 

Peak zones by operators. However, Fracasso and others (1988) 

suggested that hydrocarbons tend to be concentrated in upper 

Travis Peak sandstones because these sandstones are encased in 

shales that provide effective traps. Underlying low-sinuosity fl uvial sandstones, comprising the bulk of the Travis Peak Formation, form a highly interconnected reservoir not only by virtue 

of their inherent multistory, multilateral sand-body geometries 

but also because of the abundance of natural vertical fractures 

within the highly quartz cemented, fl uvial-sandstone sequence. 

Thus, the thick fl uvial sequence seems to provide an effective 

upward migration pathway for gas. Data from Woodlawn fi eld 

in Harrison County, Texas, corroborate this interpretation. 

Union Chicot

LaSalle

Grant

Kaufman

VILLAGE

KNOWN FIELDS WITH TRAVIS PEAK FORMATION

HYDROCARBON-WATER CONTACTS

Gas-water contact inferred from flank wells that tested water

Bossier

TEXAS

LOUISIANA

ARKANSAS

LOUISIANA

MISSISSIPPI

Cass Lafayette Columbia

Webster

Caddo

Marion

Harrison

Claiborne

Panola

Shelby

De Soto

Sabine

Natchitoches

Red River

Beinville

Lincoln

Jackson

Union

Ashley

Morehouse

West

Carroll

East

Carroll

Richland

Madison

Franklin

Tensas

Catahoula

Concordia

Winn LOUISIANA

Caldwell

DOWNSVILLE

Dallas

Gulf of Mexico

TX

LA

OK AR

DETAIL MS AL

AREA

LOCATION MAP

WASKOM

BETHANYLONGSTREET

CASPIANA

BEAR CREEK

BRYCELAND

0 20 40 Miles 10 30

Hydrocarbon-water contacts reported in public literature

without gas from Travis Peak sandstones

RUSTON

SIMSBORO

CHENIERE

CREEK

SUGAR

CREEK

COTTON

PLANT

Ouachita

Figure 12. Map of northern Louisiana showing fi elds in which hydrocarbon-water contacts have been identifi ed in Travis Peak (Hosston) Formation sandstone reservoirs. Dark shading indicates fi elds in which Travis Peak hydrocarbon-water contacts have been reported in publicly 

available literature (see table 1). Light shading indicates fi elds in which gas-water contacts are inferred based on presence of fl ank wells that 

tested water only, without gas, identifi ed from IHS Energy data (PI/Dwights Plus of Petroleum Information/Dwights, d.b.a. IHS Energy Group). 

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 27
According to Al Brake (BP Amoco engineer, oral commun., 

2000), mud-log gas shows are prominent in sandstones within 

the upper 500 ft of the Travis Peak at Woodlawn fi eld but are 

generally absent in sandstones throughout the middle and lower 

Travis Peak. Completion attempts within the few thin middle 

and lower Travis Peak zones that exhibit gas shows and higher 

resistivities generally yield marginal to noncommercial quantities of gas before depleting and (or) giving way to water production (Al Brake, BP Amoco engineer, oral commun., 2000). 

In summary, permeability within much of the Travis Peak 

Formation is signifi cantly higher than the 0.1-mD cutoff value 

defi ning tight-gas sandstones. Traps for much of the gas in 

Travis Peak sandstone reservoirs are provided by mudstones 

that encase sandstone units in the upper portions of the formation rather than by inherent low permeability of the sandstone 

reservoirs. Travis Peak sandstone reservoirs exhibit reservoir 

properties and trapping patterns that are not entirely characteristic of basin-centered gas reservoirs, in which inherent, 

ubiquitous, low-permeability provides a seal for thermally 

generated gas. 

Abnormally Pressured Reservoirs

Based on the fl uid-pressure-gradient cutoff value of 0.55 

psi/ft, above which Spencer (1987) considered reservoirs with 

highly saline waters to be signifi cantly overpressured, virtually all Travis Peak sandstone reservoirs across northeastern 

Texas and northern Louisiana are normally pressured (fi gs. 9 

and 10). Some Travis Peak reservoirs have slightly elevated 

FPGs, between 0.43 and 0.54 psi/ft, and a few exhibit subnormal FPGs, between 0.36 and 0.38 psi/ft. Based on data from 

24 Travis Peak fi elds, the only Travis Peak sandstone reservoir 

that is signifi cantly overpressured is one with an FPG of 0.79 

psi/ft in Clear Branch fi eld, Jackson Parish, Louisiana (fi g. 

9). Three shallower Travis Peak sandstone reservoirs in Clear 

Branch fi eld, however, have normal FPGs of 0.47 to 0.48 psi/ft 

(fi g. 9). Although pressure-gradient data for Travis Peak reservoirs in northern Louisiana come from various depths throughout the Travis Peak Formation, most pressure data for Travis 

Peak reservoirs in northeastern Texas are from sandstones 

within the upper 300 ft of the formation. Of 17 FPG values for 

Hunt

Ellis

Hopkins Franklin

Morris Cass

Dallas

Kaufman

TRAVIS PEAK FORMATION SANDSTONE PERMEABILITY (mD)

Angelina

Nacogdoches

Houston

Rockwall

0 20 40 Miles 10 30

TEXAS

LOUISIANA

AR

LA

Collin

Navarro

Hill

Falls

Limestone Freestone

Leon

Anderson

Cherokee

Rusk

Smith

Henderson

Van Zandt

Gregg

Upshaw

Wood

Camp Rains

Titus

Marion

Harrison

Miller

Caddo

De Soto

Shelby

Panola

Sabine

San Augustine

Hemphill

Gulf of Mexico

TX

LA

OK AR

DETAIL MS AL

AREA

LOCATION MAP

TRI CITIES

0.1 to 85.0

PERCY WHEELER

0.076 (avg)

TRAWICK

0.1 (avg)

PINEHILL

SOUTHEAST

1.3 (avg)

HENDERSON

72

CYRIL

<1 to 200

BETHANYLONGSTREET

115

WASKOM

65

WILLOW

SPRINGS

20

1.48 (avg)

APPLEBY

NORTH

0.015 (avg)

WHELAN

0.05 to 83.0

0.153 (avg)

Figure 13. Map of northeastern Texas showing measured and average (avg) values of permeability for productive Travis Peak Formation 

sandstones in various fi elds. Multiple values of permeability for a particular fi eld are measured values for different stacked sandstone reservoirs 

in that fi eld. Permeability data are shown in table 1 along with sources for those data.

28 Geologic Studies of Basin-Centered Gas Systems
Travis Peak reservoirs in northeastern Texas, six are believed 

to be from reservoirs at depths of 500 ft or greater below top 

of the Travis Peak (table 1 and fi g. 9). Four of these six FPGs 

are normal, and two are subnormal. Al Brake (BP Amoco 

engineer, oral commun., 2000) identifi ed two additional fi elds 

in northeastern Texas, Woodlawn and Carthage fi elds, where 

Travis Peak reservoirs exhibit normal FPGs throughout the 

formation. Al Brake is not aware of any signifi cantly overpressured Travis Peak reservoirs in northeastern Texas. Available 

data, therefore, suggest the absence of signifi cantly overpressured reservoirs throughout the Travis Peak Formation in 

northeastern Texas. If overpressured reservoirs do occur within 

the middle and lower Travis Peak Formation in northeastern 

Texas, they probably are a local phenomenon without regional 

extent.

A number of Travis Peak reservoirs exhibit subnormal 

FPGs (0.27 to 0.38 psi/ft) (fi gs. 9 and 10). It is possible that 

these lower FPGs represent errors in measurement or lack of 

development of equilibrium conditions during tests in lowpermeability rock. Also it is possible that a subnormal FPG for 

a particular sandstone reservoir refl ects depletion of pressure 

caused by hydrocarbon production from another Travis Peak 

sandstone that is in pressure communication with the apparently subnormally pressured interval. However, if one assumes 

that all the subnormal FPG values shown in fi gures 9 and 10 

refl ect original, virgin pressures unaffected by depletion, one 

might argue that they represent pressure declines associated 

with Tertiary uplift and erosion. If that were true, perhaps 

many Travis Peak reservoirs that today are normally pressured 

or slightly overpressured might have been signifi cantly overpressured prior to Tertiary uplift and erosion. 

During Tertiary uplift between 58 and 46 Ma, approximately 1,500 ft of strata were removed across much of northeastern Texas (Dutton, 1987; Laubach and Jackson, 1990; 

Jackson and Laubach, 1991). However, if much of the gas 

found in Travis Peak reservoirs was derived from Bossier 

Shale source rocks, migration of that gas into Travis Peak 

sandstones probably commenced between 57 and 45 Ma 

(Dutton, 1987; Hermann and others, 1991). Therefore, most 

of the thermally generated gas that presumably would have 

Lafayette Columbia

Union

Ashley

West

Carroll

East

Carroll

Richland

Kaufman

TRAVIS PEAK FORMATION SANDSTONE PERMEABILITY (mD)

Bossier

Miller

TEXAS

LOUISIANA

ARKANSAS

LOUISIANA

MISSISSIPPI

Cass

Webster

Caddo

Marion

Harrison

Claiborne

Panola

Shelby

De Soto

Sabine

Natchitoches

Red River

Beinville

Lincoln

Jackson

Union Morehouse

Chicot

Ouachita

Madison

Franklin

Tensas

Catahoula LaSalle

Grant

Concordia

Winn LOUISIANA

Caldwell

0 20 40 Miles 10 30

Dallas

Gulf of Mexico

TX

LA

OK AR

DETAIL MS AL

AREA

LOCATION MAP

WASKOM

65

BETHANYLONGSTREET

115

LEATHERMAN

CREEK

0.7

SIBLEY ADA

BEAR CREEK

BRYCELAND

VILLAGE

706

131

LISBON

500

SUGAR

CREEK

65

CHOUDRANT

250

SIMSBORO

500

2 to 50

CLEAR BRANCH

3.8

1.4

0.6

0.3

CHENIERE

CREEK

6.0

COTTON

PLANT

166

170

Figure 14. Map of northern Louisiana showing measured values of permeability for productive Travis Peak Formation sandstones in various

fi elds. Multiple values of permeability for a particular fi eld are measured values for different stacked sandstone reservoirs in that fi eld. 

Permeability data are shown in table 1 along with sources for those data.

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 29
caused development of overpressured reservoirs probably 

migrated into Travis Peak reservoirs following Tertiary uplift. 

If Tertiary uplift and erosion resulted in pressure reduction 

within Travis Peak sandstone reservoirs, subsequent introduction of thermally generated gas has not been able to produce 

signifi cant widespread overpressure within those reservoirs. 

Perhaps most subnormal FPGs calculated for Travis Peak reservoirs refl ect (1) depletion of pressure caused by hydrocarbon 

production from another Travis Peak sandstone reservoir that 

is in pressure communication with the apparently subnormally 

pressured reservoir interval or (2) lack of pressure buildup to 

equilibrium conditions during the pressure test. The best available data indicate that widespread, abnormally high pressure 

gradients caused by thermal generation of gas that is typical 

of basin-centered gas accumulations does not occur within the 

Travis Peak Formation. Stated another way, the occurrence of 

normally pressured, gas-charged sandstone reservoirs throughout most of the Travis Peak Formation across the northern 

Gulf Coast Basin suggests that a signifi cant basin-centered 

accumulation is not present within the Travis Peak. 

It is interesting to speculate on the absence of widespread 

overpressured reservoirs in the Travis Peak across eastern 

Texas and northern Louisiana. Perhaps there is insuffi cient 

hydrocarbon charge associated with absence of proximal 

source rocks or with poor migration pathways from stratigraphically or geographically distant source rocks. Additionally, relatively high matrix and fracture permeability of signifi cant volumes of Travis Peak sandstone reservoirs might 

prevent the Travis Peak Formation as a whole from retarding 

upward migration of gas suffi ciently to enable abnormally high 

pressures to develop. The lack of regional overpressures within 

the Travis Peak Formation could be explained by insuffi cient 

hydrocarbon charge relative to effectiveness of Travis Peak 

sandstone reservoirs to transmit, rather than retard the fl ow 

of, gas.

Restriction of reservoir bitumen in Travis Peak sandstones to reservoirs in the uppermost 300 ft of the formation 

might be signifi cant in understanding hydrocarbon charge. 

Reservoir bitumen probably formed in pores of Travis Peak 

sandstones from deasphalting of oil caused by dissolution of 

gas in the oil. Was oil present throughout most of the Travis 

Peak Formation, and were suffi cient quantities of gas developed, or introduced, only in the upper 300 ft of the Travis Peak 

to promote deasphalting there? Or was oil that experienced 

deasphalting originally present only in sandstones within the 

uppermost 300 ft of the formation, refl ecting limited charge 

of oil into the Travis Peak? The latter explanation seems more 

logical, because, even within upper Travis Peak sandstones, 

bitumen occurs only in clean, well-sorted, rippled and crossbedded sandstones. The absence of bitumen in burrowed, 

shaly, poorly sorted sandstones in the upper Travis Peak suggests that charge was insuffi cient to drive oil through smaller 

pore throats. Thus, with respect to the oil phase, hydrocarbon 

charge seems to be limited.

An additional question concerns the source of gas that 

promoted deasphalting of Travis Peak oil to produce reservoir bitumen. Was the gas generated in place through thermal 

alteration of Travis Peak oil, or was it introduced from some 

external source? The answer is unknown, although the level of 

kerogen maturity in mudstones interbedded with Travis Peak 

sandstone reservoirs suggests that oils in Travis Peak sandstones were subjected to temperatures suffi cient to generate 

gas internally (Dutton, 1987). However, the extensive volume 

of gas within Travis Peak reservoirs regionally might suggest 

that much of that gas was derived from an external source, 

presumably the Bossier Shale or Smackover laminated lime 

mudstones, or both. Thus, there might have been a two-phase 

migration of hydrocarbons into Travis Peak reservoirs, perhaps 

similar to that described in general terms by Gussow (1954). 

As Bossier and Smackover source rocks were buried, they fi rst 

generated oil, some of which might have migrated into Travis 

Peak sandstones where it was trapped. With continued burial, 

Bossier and Smackover source rocks reached the gas window, 

spawning an episode of gas generation that might be continuing today. This later gas might have caused deasphalting of 

previously emplaced oil in Travis Peak sandstones, as well as 

displacement of oil from some Travis Peak reservoirs. However, as evidence seems to suggest a limited charge of oil into 

Travis Peak reservoirs, perhaps gas charge also is suffi ciently 

limited relative to transmissibility of Travis Peak sandstone 

reservoirs to prohibit development of regionally overpressured 

reservoirs and accompanying basin-centered gas.

Hydrocarbon-Water Contacts

Perhaps the most defi nitive criterion for establishing the 

presence of a basin-centered gas accumulation is absence of 

gas-water contacts. Gas-water contacts are distinctive features of conventional gas accumulations. The presence of a 

gas-water contact indicates a change from gas-saturated to 

water-saturated porosity within a particular reservoir unit. This 

implies that a well drilled into that reservoir structurally below 

the gas-water contact should encounter only water, thereby 

demonstrating the absence of a continuous-gas accumulation 

in that immediate area. Documentation of the occurrence of 

gas-water contacts within a particular stratigraphic unit in 

various gas fi elds distributed across a particular basin argues 

strongly against presence of a continuous- or basin-centered 

gas accumulation within that particular interval in the basin.

Hydrocarbon-water contacts have been documented 

within Travis Peak sandstone reservoirs in 13 fi elds (fi gs. 

11 and 12) across eastern Texas and northern Louisiana. As 

discussed above and as indicated by dashed fi eld outlines in 

fi gure 11, four additional Travis Peak fi elds probably also have 

hydrocarbon-water contacts, depending upon interpretation of 

the term “elevation of bottom of gas” as reported by Herald 

(1951). Data for many Travis Peak fi elds presented in Shreveport Geological Society Reference Reports (1946, 1947, 1951, 

1953, 1958, 1963, 1987) and Shoemaker (1989) either do 

not mention hydrocarbon-water contacts or report that none 

were encountered. However, because many of those reports 

30 Geologic Studies of Basin-Centered Gas Systems
were prepared not long after fi elds were discovered, suffi cient 

development drilling may not have occurred to encounter 

hydrocarbon-water contacts. In other cases, fl uid contacts were 

not included as part of the fi eld description. Lack of reported 

Travis Peak hydrocarbon-water contacts in such fi eld reports, 

therefore, should not be interpreted as absence of oil-water or 

gas-water contacts in those fi elds. Consequently, it is likely 

that considerably more of the Travis Peak fi elds (fi gs. 1A and 

1B) have hydrocarbon-water contacts than illustrated in fi gures 

11 and 12. 

Supporting that inference is the inferred presence of 

Travis Peak gas-water contacts at fi elds such as BethanyLongstreet and Cheniere Creek in northern Louisiana (fi g. 12) 

based on recoveries of water without gas from production 

tests and DSTs of Travis Peak sandstone reservoirs on the 

fl anks of those fi elds. Although water recoveries from fl ank 

wells suggest the presence of gas-water contacts within Travis 

Peak reservoirs in those fi elds, gas-water contacts were not 

reported for Travis Peak reservoirs in those fi elds in Shreveport 

Geological Society Reference Reports (1963, 1987). 

As discussed above, all hydrocarbon-water contacts 

within Travis Peak sandstone reservoirs in fi elds in northeastern Texas documented in this report (table 1 and fi gure 11) 

occur in the upper 300 ft of the Travis Peak Formation. No 

documented hydrocarbon-water contacts in middle or lower 

Travis Peak reservoirs in northeastern Texas have been found. 

At Woodlawn fi eld in Harrison County, Texas, a discrete gaswater contact has not been identifi ed in the lower Travis Peak 

Formation. However, commercial gas production from the 

middle and lower Travis Peak section at Woodlawn fi eld is 

limited, and most of that interval at Woodlawn fi eld is considered water bearing, according to Al Brake (BP Amoco engineer, oral commun., 2000). In addition to sandstones within 

the upper 500 ft of the Travis Peak, a deeper sandstone interval 

about 200 ft above the bottom of the Travis Peak Formation 

produces gas in commercial quantities at Woodlawn fi eld. BP 

refers to this deeper productive interval at Woodlawn fi eld 

informally as the McGee sandstone. Al Brake reports that the 

bulk of the Travis Peak section between the McGee sandstone 

and productive sandstones in the upper 500 ft of the Travis 

Peak lacks mud-log gas shows and is not considered productive. Locally within the middle and lower Travis Peak interval 

at Woodlawn fi eld, Al Brake reports that scattered 10- or 12-ft 

sandstones locally exhibit high resistivity within the upper 1 

to 3 ft accompanied by mud-log gas shows, but show lower 

resistivity below with no mud-log gas shows. Some of these 

thin, high-resistivity intervals have been perforated and tested. 

Typical cumulative production from one of these thin intervals ranges from insignifi cant to a maximum of only about 

0.1 BCFG before the zone depletes and gives way to water 

production. Based on general lack of mud-log gas shows, 

scattered presence of only thin 1- to 3-ft, high-resistivity, gasbearing zones, and limited recovery of gas throughout the bulk 

of the Travis Peak section between the deeper McGee sandstone and the uppermost 500 ft of the formation, Al Brake (BP 

Amoco engineer, oral commun., 2000) considers the middle 

and lower Travis Peak interval at Woodlawn fi eld to be largely 

water bearing. If these reservoir and production characteristics 

are typical of other Travis Peak fi elds, this information from 

Woodlawn fi eld tends to confi rm the interpretation of Fracasso 

and others (1988) that commercial quantities of hydrocarbons 

in Travis Peak sandstones are concentrated within the sandstones in the upper 300 ft of the formation. 

Patterns of gas occurrence and production at Woodlawn 

fi eld might have signifi cance in understanding Travis Peak 

gas reservoirs at North Appleby fi eld in Nacogdoches County, 

Texas. According to Tye (1991), gas occurs throughout the 

Travis Peak Formation at North Appleby fi eld, though not necessarily in commercial amounts, and a discrete gas-water contact reportedly is not present. As at Woodlawn fi eld however, 

sandstone reservoirs throughout the Travis Peak Formation at 

North Appleby fi eld, are normally pressured (Lin and Finley, 

1985), which is not typical of basin-centered gas accumulations. Furthermore, although most of the Travis Peak section 

at North Appleby fi eld reportedly is gas charged, perforations 

in the fi eld well shown by Tye (1991) are limited to only a few 

sandstones that are capped by thicker shale units. Perforated 

sandstones in this well are restricted to two zones, one within 

the upper 500 ft of the Travis Peak between depths of 8,200 

and 8,500 ft, and a second zone about 200 ft from the bottom of 

the formation between depths of 9,800 and 10,000 ft. This pattern of perforations is strikingly similar to that described by Al 

Brake for Travis Peak sandstones at Woodlawn fi eld. Although 

cores were cut in several intervals within the thick intervening fl uvial-sandstone section in that well at North Appleby 

fi eld, no zones were perforated between 8,500 ft and 9,800 ft. 

Examination of production-test data from other wells in North 

Appleby fi eld indicates that most perforations are restricted 

to the upper 500 ft of the Travis Peak section. Only two other 

wells in North Appleby fi eld were found with perforations in 

the deeper interval about 200 ft from the base of the Travis 

Peak. Initial-production rates of 72 and 114 thousand cubic ft 

of gas per day (MCFD) from lower Travis Peak perforations in 

these two wells suggest that this deeper zone at North Appleby 

fi eld probably is marginally commercial to noncommercial. 

Restriction of perforations within the middle and lower Travis 

Peak Formation at North Appleby fi eld to one zone about 200 ft 

from the bottom of the Travis Peak shows striking resemblance 

to the pattern observed at Woodlawn fi eld, where the normally 

pressured middle and lower Travis Peak section reportedly is 

largely water bearing. Although mud-log data from wells in 

North Appleby fi eld were not available for this study, one might 

wonder if the bulk of the middle and lower Travis Peak section 

there lacks gas shows and largely is water bearing despite the 

report of being gas charged by Tye (1991). Tye’s report that the 

middle and lower Travis Peak Formation at North Appleby fi eld 

is gas charged was based on personal communication to him 

with no supporting data and was accompanied by the qualifi -

cation that gas might not be present in commercial quantities 

throughout the section. Such qualifi cation bears some resemblance to the situation described by Al Brake at Woodlawn fi eld, 

where scattered thin, highly resistive zones in the middle and 

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 31
lower Travis Peak produce small amounts of gas before depleting and yielding water. Finally, in considering the potential for 

basin-centered gas, it is signifi cant that, despite the lack of documented gas-water contacts within the middle and lower Travis 

Peak at Woodlawn and North Appleby fi elds, the entire Travis 

Peak interval at both fi elds reportedly is normally pressured. 

In summary, hydrocarbon-water contacts in Travis Peak 

sandstone reservoirs have been documented at various depths 

within the Travis Peak Formation in nine fi elds in northern Louisiana. In northeastern Texas, hydrocarbon-water contacts have 

been reported within Travis Peak sandstone reservoirs in eight 

fi elds, but these all occur within the upper 300 to 500 ft of the 

Travis Peak Formation. Rather than being clustered in a small 

area, however, these fi elds with documented hydrocarbon-water 

contacts are widely distributed across the eastern-Texas and 

northern-Louisiana Travis Peak productive trend. Wide distribution of such conventional hydrocarbon accumulations with 

hydrocarbon-water contacts suggests the absence of signifi cant 

basin-centered gas accumulations within the entire Travis Peak 

Formation in northern Louisiana and within the upper 500 ft 

of the Travis Peak Formation in northeastern Texas. Data on 

hydrocarbon-water contacts in the lower three-fourths of the 

Travis Peak section in northeastern Texas are limited and less 

conclusive. At fi elds such as North Appleby and Woodlawn in 

northeastern Texas, clearly defi ned gas-water contacts reportedly are not present or have not been identifi ed. Travis Peak 

reservoirs at North Appleby and Woodlawn fi elds, however, 

are normally pressured, which is not characteristic of basincentered gas accumulations. The best available data suggest 

that the lower three-fourths of the Travis Peak Formation across 

much of northeastern Texas is characterized by a general lack of 

mud-log gas shows and by only a few gas-charged sandstones 

that yield marginal to noncommercial gas production before 

depleting and giving way to water production. Operators consequently seem to focus efforts on Travis Peak completions 

within sandstone reservoirs in the uppermost 300 to 500 ft of 

the Travis Peak Formation, resulting in limited data in the lower 

three-fourths of the formation. Although pressure data from 

depths below 500 ft of top of the Travis Peak are limited, data 

from eight fi elds indicate normal or subnormal FPGs and suggest absence of signifi cant overpressure throughout the Travis 

Peak Formation in northeastern Texas. In the absence of documented gas-water contacts below 500 ft of top of the Travis 

Peak Formation in northeastern Texas, limited data indicating 

presence of abundant water-bearing sandstones and a lack of 

signifi cant overpressured reservoirs together suggest absence 

of widespread basin-centered gas accumulations within the 

middle and lower Travis Peak. 

Conclusions

 1. The Travis Peak (Hosston) Formation is a Lower Cretaceous basinward-thickening wedge of terrigenous 

clastic sedimentary rocks that underlies the northern 

Gulf Coast Basin from eastern Texas across northern 

Louisiana into southern Mississippi and eastward. 

Clastic infl ux was focused in two main fl uvial-deltaic 

depocenters associated with the ancestral Red River in 

northeastern Texas and the ancestral Mississippi River 

in southern Mississippi and northeastern Louisiana. 

 2. Across its hydrocarbon-productive trend in northeastern Texas, the Travis Peak Formation is divided into 

three informal units based on relative amounts of sandstone and shale. A thin lower interval consists of mixed 

sandstones and shales interpreted as delta-fringe deposits. It is gradationally overlain by a thick, sandstonerich sequence that forms the bulk of the Travis Peak 

section comprised primarily of stacked, braidedchannel sandstones grading upward into meanderingchannel deposits. The third and uppermost interval 

consists of mixed sandstone and mudstone interpreted 

as coastal-plain, paralic, and marine deposits. Upward 

stratigraphic evolution from braided through meandering fl uvial systems to paralic and marine strata refl ects 

an overall transgression and relative rise in sea level 

that occurred during Travis Peak deposition.

 3. Most hydrocarbon production from the Travis Peak 

Formation in northeastern Texas and northern Louisiana is from drilling depths of 6,000 to 10,000 ft. 

Throughout that interval, porosity and permeability 

of Travis Peak sandstones decrease signifi cantly with 

depth. In northeastern Texas, average porosity of clean 

Travis Peak sandstones decreases from 16.6 percent at 

6,000 ft to 5.0 percent at 10,000 ft. Average stressed 

permeability of clean sandstones decreases by four 

orders of magnitude from 10 mD at 6,000 ft to 0.001 

mD at 10,000 ft. Decrease in porosity with depth 

results primarily from (a) increasing amount of quartz 

cement, and (b) decrease in amount of secondary 

porosity, which was derived almost exclusively from 

dissolution of feldspar. Decrease in permeability with 

depth occurs mainly because of (a) decrease in porosity, which in turn is caused principally by increasing 

quartz cement, and (b) increasing overburden pressure 

that closes small-diameter pore throats.

 4. Reservoir properties of many Travis Peak sandstones 

are signifi cantly better than those characteristic of 

basin-centered gas reservoirs in which inherent, ubiquitous, low-permeability provides an internal, leaky 

seal for thermally generated gas. Although Travis 

Peak sandstones have received “tight-gas” designation 

across selected portions of eastern Texas and northern 

Louisiana, at depths less than 7,500 ft in northeastern 

Texas, the sandstones often exhibit permeabilities well 

above the 0.1-mD cutoff for qualifi cation as a tight-gas 

reservoir. At depths less than 6,000 ft, permeability 

can exceed 100 mD. At depths below 8,000 ft, where 

matrix permeability generally is less than 0.1 mD as 

a result of extensive quartz cementation, natural fractures are common, imparting fracture permeability to 

32 Geologic Studies of Basin-Centered Gas Systems
the reservoir. In northern Louisiana where interdeltaic 

sandstones are separated by shale intervals, hydrocarbon production comes from sandstones throughout the 

Travis Peak. In northeastern Texas, most production of 

oil and gas from the Travis Peak comes from sandstone 

reservoirs in the upper 300 ft of the formation. This 

seems to refl ect a concentration of hydrocarbons in the 

upper Travis Peak, though in some fi elds, sandstones 

throughout the Travis Peak Formation reportedly are 

gas charged. Concentration of oil and gas probably 

occurs in upper Travis Peak sandstones because these 

meandering-channel, tidal-channel, and tidal-fl at sandstones are encased in thick shales that provide effective 

seals. Underlying low-sinuosity fl uvial sandstones, 

comprising the bulk of the Travis Peak Formation, 

form a highly interconnected network because of their 

inherent multistory, multilateral sand-body geometries; 

there is also an abundance of natural vertical fractures 

within the highly quartz-cemented sequence. Thus, 

the thick fl uvial sequence with its lack of thick, widespread shale barriers seems to provide an effective 

upward-migration pathway for gas rather than affording inherent sealing capabilities typical of reservoirs 

harboring basin-centered gas accumulations. 

 5. Source rocks generating the hydrocarbons produced 

from Travis Peak sandstone reservoirs are not proximal 

to those reservoirs. Vitrinite refl ectance (Ro) of Travis 

Peak shales interbedded with reservoir sandstones in 

eastern Texas indicate that they have passed through 

the oil window and are approaching the onset of drygas generation. However, these shales are primarily 

oxidized fl ood-plain shales with total organic carbon 

content less than 0.5 percent and consequently are not 

considered likely sources of oil and gas. Travis Peak 

marine shales depositionally downdip in the Gulf Coast 

Basin in central Louisiana might have generated hydrocarbons, but relatively long distance lateral migration 

would be necessary. Most likely source rocks for gas 

and oil produced from Travis Peak sandstones are the 

Jurassic Bossier Shale of the underlying Cotton Valley 

Group and stratigraphically lower, laminated, carbonate mudstones of the Jurassic Smackover Formation. 

Burial- and thermal-history data for eastern Texas and 

northern Louisiana suggest that onset of dry-gas generation from Smackover mudstones and the Bossier 

Shale occurred about 80 Ma and 57 Ma, respectively. 

The Bossier Shale, however, is separated from Travis 

Peak reservoirs by at least 1,000 ft of tight Cotton 

Valley sandstones and interbedded shales, and also by 

the tight Knowles Limestone, across much of the area.

 6. Unlike basin-centered gas reservoirs, which generally are abnormally pressured, Travis Peak sandstone 

reservoirs across eastern Texas and northern Louisiana 

commonly are normally pressured. Of 24 fi elds for 

which pressure data are reported here, only one has a 

Travis Peak reservoir that is considered signifi cantly 

overpressured, i.e., with FPG greater than 0.55 psi/

ft. At Clear Branch fi eld, Louisiana, one sandstone 

has a FPG = 0.79 psi/ft, but three other Travis Peak 

sandstone reservoirs within that fi eld are normally 

pressured. In northern Louisiana, pressure data are 

available from sandstones throughout the Travis Peak, 

whereas in northeastern Texas, most available pressure data are from reservoirs in the upper 300 to 500 

ft of the Travis Peak Formation. Limited data from the 

lower three-fourths of the Travis Peak in northeastern 

Texas suggest absence of signifi cant overpressures in 

that interval, too. Some fi elds exhibit underpressured 

reservoirs, with FPGs ranging from 0.27 to 0.38 psi/ft. 

If these data are accurate, they might suggest pressure 

decrease associated with Tertiary uplift and erosion 

across northeastern Texas. Most of the gas presumably generated from Bossier and Smackover source 

rocks probably migrated into Travis Peak reservoirs 

following Tertiary uplift. If Tertiary uplift and erosion 

resulted in pressure reduction within Travis Peak sandstone reservoirs, subsequent introduction of thermally 

generated gas has not been able to produce signifi cant 

widespread overpressured reservoirs. Thus, Travis Peak 

reservoirs across the northern Gulf Coast Basin are 

characterized by normal to slightly below normal pressures. Widespread abnormally high pressure caused 

by thermal generation of gas that is typical of basincentered gas accumulations does not occur within the 

Travis Peak Formation.

 7. The presence of a gas-water contact perhaps is the 

most defi nitive criterion suggesting that a gas accumulation is conventional rather than a “sweet spot” 

within a basin-centered, continuous-gas accumulation. 

Hydrocarbon-water contacts within Travis Peak sandstone reservoirs have been documented in nine fi elds 

in northern Louisiana and eight fi elds in northeastern 

Texas. In all eight fi elds in northeastern Texas, however, hydrocarbon-water contacts occur in sandstone 

reservoirs in the uppermost 300 to 500 ft of the Travis 

Peak Formation. In northeastern Texas, no documented 

gas-water contacts have been found in Travis Peak 

reservoirs in the lower three-fourths of the formation. 

In a few Travis Peak fi elds, such as North Appleby 

fi eld, Nacogdoches County, Texas, gas reportedly is 

present, though not always in commercial amounts, in 

sandstones throughout the Travis Peak Formation, and 

a discrete gas-water contact reportedly is not present. 

However, Travis Peak reservoirs at North Appleby fi eld 

are normally pressured. Perhaps vertically extensive 

gas-water transition zones with poorly defi ned gaswater contacts occur in some Travis Peak reservoirs 

such as those at North Appleby fi eld, as is characteristic of normally pressured conventional gas accumulations in low-permeability reservoirs. Alternatively, the 

pattern of perforated intervals at North Appleby fi eld 

is similar to that at Woodlawn fi eld, Harrison County, 

Potential for a Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, U.S.A. 33
Texas, where most of the middle and lower Travis Peak 

section reportedly is water bearing. Fields with clearly 

documented hydrocarbon-water contacts throughout 

the Travis Peak in Louisiana and within the upper 300 

to 500 ft of the formation in northeastern Texas are 

distributed widely across the Travis Peak productive 

trend. Wide distribution of conventional hydrocarbon 

accumulations with discrete hydrocarbon-water contacts indicates absence of a signifi cant basin-centered 

gas accumulation within the Travis Peak Formation in 

Louisiana, and within the upper 300 to 500 ft of the 

Travis Peak in northeastern Texas. 

 8. Insuffi cient hydrocarbon charge together with suffi ciently high reservoir permeability might explain 

why Travis Peak sandstone reservoirs generally are 

normally pressured and commonly exhibit discrete 

hydrocarbon-water contacts. Perhaps lack of proximal 

source rocks and lack of effective migration pathways from stratigraphically or geographically distant 

source rocks result in insuffi cient hydrocarbon charge. 

Furthermore, Travis Peak sandstone reservoirs might 

have suffi ciently high matrix and fracture permeability 

through suffi cient stratigraphic thickness and across 

suffi cient geographic extent to allow upward migration of gas, to the degree that abnormally high pressure 

and basin-centered gas cannot develop. Most Travis 

Peak hydrocarbon accumulations in northeastern Texas 

occur in the uppermost 300 to 500 ft of the formation within sandstones that are encased completely in 

marine shale.

 9. Lack of proximal source rocks, the relative abundance 

of reservoir sandstone with signifi cant matrix and fracture permeability, and especially the abundance of normally pressured reservoirs together with widespread 

presence of hydrocarbon-water contacts suggest that 

basin-centered gas is absent or insignifi cant within the 

Travis Peak Formation. If any areas of continuous gas 

occur within the Travis Peak Formation, they probably 

occur within the lower three-fourths of the Travis Peak 

in northeastern Texas, southwest of the Sabine uplift, 

and probably are not suffi ciently large to have a signifi -

cant impact on hydrocarbon resource assessment for 

the Travis Peak.

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Manuscript approved for publication January 30, 2003

Published in the Central Region, Denver, Colorado

Editing—Richard W. Scott, Jr.

Graphics, layout, photocomposition—William E. Sowers

36 Geologic Studies of Basin-Centered Gas Systems